2016 annual report - keystone-group.ca · keystone royalty corp. 2016 annual report 1 | p a g e...

2016 Annual Report

Keystone Royalty Corp. 2016 Annual Report 1 | P a g e

Contents 2016 Highlights President’s Letter Property Review Financial Review: Management’s Discussion and Analysis Reviewed Financial Statements Corporate Directory

Page 3 Page 8 Page 11 Page 18 Page 33

Our Business Keystone Royalty Corp. (“Keystone” or the “Company”) is a Saskatchewan based privately-held, land and royalty company. The Company was incorporated in 1950 as Keystone Petroleums Ltd. (“KPL”) and until 2002, was headquartered in Pittsburgh, PA. KPL was acquired by Keystone Energy Inc. (“KEI”) in February 2002. Prior to the corporate disposition of KEI to StarPoint Energy Ltd. in September 2004, the shares of KPL were acquired by 101051712 Saskatchewan Ltd. Effective December 31, 2004, 101051712 Saskatchewan Ltd. and KPL were amalgamated and continued as Keystone Petroleums Ltd. In December 2006, the Company changed its name from Keystone Petroleums Ltd. to the current name. At year end December 31, 2016, Keystone owned fee title interests in over 299,000 gross acres of fee mineral title within the Provinces of Saskatchewan, Alberta, Manitoba and Ontario. Keystone holds additional interests in another 35,000 gross acres of non-titled lands.

Annual General Meeting The Annual Meeting of Shareholders of Keystone will be held in the Main Boardroom at the Corporation’s offices at 2530 Sandra Schmirler Way, Regina, Saskatchewan on Wednesday, June 14, 2017 at 3:00 p.m.

Selected Abbreviations

Bbl barrel Bbls barrels Boe barrel of oil equivalent Boes barrels of oil equivalent Boepd barrels of oil equivalent per day

Bopd barrels of oil per day Mcf million cubic feet NGL natural gas liquids WTI West Texas Intermediate


2016 Highlights Year Ended December 31 2016 2015 Change FINANCIAL

Gross revenue $ 11,644,275 $ 14,257,939 (18%)

Funds generated by operations $ 8,496,949 $ 10,355,674 (18%)

Per Share – basic $ 1.06 $ 1.31 (19%)

Capital expenditures & acquisitions $ 1,345,261 $ 19,057,904 (93%)

Total debt $ 3,400,000 $ 5,450,000 (38%)

Dividends $ 5,543,680 $ 11,610,690 (52%)

Per Share - Annual $ 0.70 $ 1.00 (30%)

Per Share - Special $ - $ 0.50 (100%)

Common shares outstanding Basic 8,022,167 7,891,554 2% Diluted 8,699,167 8,563,554 2%

OPERATIONAL (units as noted)

Average daily production (Boepd) 788 788 0%

Average realized price ($/Boe) $ 39.72 $ 48.13 (17%)

Fee Mineral Lands (title)

Gross (Acres) 299,817 295,242 2%

Net (Acres) 98,322 96,146 2%

Non-titled lands

Gross (Acres) 35,593 39,190 (9%)


President’s Letter Similar to 2015, in the past year our Company attempted to achieve a balance of continued growth and fiscal sustainability. As one might expect, with the substantial macro-economic challenges that our industry faced in the past two years, this continued to be a significant challenge. After declining 48% from 2014 to 2015, oil prices showed continued weakness in 2016, averaging US $43.32 per Bbl in 2016, a further drop of 11% from the prior year average of US $48.80 per Bbl. Very few businesses can maintain profitability in the face of such a significant and prolonged price weakness in its primary revenue source. Still, by almost every measure or metric (other than commodity pricing), 2016 was again a solid year for our Company. We completed two separate fee mineral title land acquisitions in 2016, comprised of 3,760

gross (960 net) acres of non-producing land in South East Saskatchewan. This is considerably less than prior years, as competition in the royalty space continues to make acquisitions, at reasonable prices, an elusive aspect of our business. In aggregate, we expended only $86,500 on fee mineral title acquisitions in 2016 ($282,448 in 2015).

Combined oil & gas equivalent production volumes were unchanged year over year, holding at exactly the same level as 2015 (788 Boepd), despite the low oil price environment. Gas volumes increased 35%, accounting for 158 Boepd (346,832 Mcf per day) in the past year. As a result, our Oil and NGL (liquids) weighting decreased to 80% from 87% in 2015. Third party drilling rebounded somewhat, as 27 new wells were drilled on our lands in 2016 (up from 19 in 2015). By comparison, the 10 year average is 36.2 wells per year. While the current number is below our historical average, it is still reflective of the highly prospective and economic profile of our lands.


During the past several years, our Company’s revenues and the dividend paid on your shares has reflected the volatility of the underlying commodity price. In Q1 2015, our annual dividend was increased 25% (from $0.80 per share in the prior year, to $1.00 per share). Unfortunately, the continued drop in oil prices over the balance of 2015, resulted in the dividend being reduced in Q2 2016, by 40% (to $0.60 per share, or $0.15 per share per quarter). While this was the first reduction in our dividend since its inception in 2006, we felt that it was a prudent measure which would ensure the sustainability of the dividend over the balance of 2016. While oil prices have not fully recovered to pre-2015 levels, they have stabilized (at least for now) at or near US $50 WTI level. As a result, in December 2016, the Board approved an increase in our dividend to $0.80 per share (paid $0.20 per share quarterly), effective January 1, 2017. Our dividend will continue to be reviewed and adjusted (increased or decreased), as our free cash flow permits. In addition to taking steps necessary to right-size our dividend in 2015, we also took steps to reduce our total general and administrative (“G&A”) expenses during the past year. Total G&A was reduced 7% in 2015, from $1.65 million to $1.53 million. In 2015, a large component of this savings resulted from your management team electing to forego performance bonuses (something that many publicly-traded energy companies were unwilling to do). Our focus on our cost structures continued in 2016, with G&A declining a further 18% in the past year, to $1.25 million. To put this in context, total G&A has now returned to approximately 2012 levels, and are currently 24% less than the “high-water” mark of $1.65 million in 2014. On a per unit basis, the efficiencies and the commitments made by our employees is even more compelling as 2016 G&A was $4.34/Boe, down from $5.31/Boe in 2015 (and $7.98/Boe in 2014). Again, I want to thank our employees for continuing to act like owners, rather than employee managers.

Our business model has evolved and is now reflected in the following core principles:

1. Pursue accretive fee title and royalty acquisitions to complement our organic growth; 2. Pursue development of our lands, either indirectly by third party exploration

companies or directly through company initiated drilling programs; and 3. Acquire strategic equity investments in other high-growth oriented energy companies.


Operational Review Continued low oil prices muted drilling both in our core area of SE Saskatchewan, and for that matter the entire world. Of the 27 new wells drilled on our lands in 2016, nearly 55% were development horizontals in the Bakken formation. The balance were drilled into the shallower Mississippian Aged formations, predominantly in the Frobisher and Alida. Not surprisingly, those three plays still provided top decile economics even at current strip pricing. Crescent Point Energy Corp. (“Crescent Point”) was again the most active third party driller on our lands, accounting for 67% of the new development on our lands. Twenty of the 27 new wells drilled on our lands in 2016 were not put on production until the second half of the year. Six of those wells were not producing until after year end. As a result, our production declined from Q1 2016 (897 Boepd) to a low of 708 Boepd in Q3, before recovering somewhat in Q4 2016 where we averaged 769 Boepd. At the time of writing, 13 new wells had been drilled on Keystone lands in 2017. Accordingly, our forecasted volumes are expected to be relatively flat throughout the balance of the year.

Industry Conditions Excess supplies of oil in North America, primarily driven by the rapid production growth from US shale plays, combined with OPEC’s decision to maintain high production rates in order to increase market share, resulted in significant price declines occurring in late 2014 and throughout 2015. The US$ WTI benchmark price averaged $48.80 per Bbl in 2015, down 48% over the prior year ($93.00 per Bbl). Oil hit a 13 year low in February 2016, but strengthened to its current rate of approximately $49 per Bbl (US). Inventories, especially in the US,


continue to be well in excess of historical averages. OPEC and non-OPEC production cuts initiated in January 2017, seem to have put a floor on oil prices at least for now.

The prolonged down-turn in oil prices has forced the majority of operators to reduce or suspend capital programs, discontinue or reduce dividends, dispose of non-core assets and downsize their workforce in an attempt to protect

their balance sheets. While we are becoming increasingly confident that the market is moving towards a more balanced supply/demand equilibrium, it will take some time for industry activity to reach a more normalized level. We are forecasting that 20 new wells will be drilled on Keystone lands in 2017. In the royalty market specifically, investor support continues to be strong, driven in part by the demand for yield in a low interest rate environment. The two notable public royalty companies, PrairieSky Royalty Ltd. and Freehold Royalties Ltd., continue to trade at market multiples far in excess of their E&P counter-parts and have been able to raise significant capital in an otherwise difficult market. These companies have been able to dominate the limited number of available acquisitions of any scale, given their cost of capital advantage over private entities such as Keystone.

Outlook Keystone’s assets continued to generate solid financial results in 2016, with cash flow of $8.5 million on $11.6 million of revenues. Management expects 2017 to be relatively similar, with both our production and our revenues essentially flat on a year over year

basis. Nevertheless, our significant royalty production and inventory of undeveloped lands provides our shareholders with considerable “torque” as oil prices eventually rise. Approximately 80% of Keystone’s fee lands are presently undeveloped, providing considerable “inventory” for future development and growth.


In addition to our core royalty business resulting from oil and gas production, in 2016 Keystone generated $36,712 in royalties and bonus consideration from our potash rights. Although modest at present, the Company has executed a total of 10 potash leases in the last couple of years, indicating the potential for long term growth. Additional product mix diversity is reflected in our acquisition of 265,000 gross acres of helium permits in 2016, from the Saskatchewan government. Keystone is now one of the largest permit holders of helium rights in the province. Additional exploratory work is being conducted by the Company on these permits, as we attempt to hi-grade our lands and in time, encourage commercial development of the resulting leases. The addition of Rejean Chabot as a consulting geologist, has increased our technical team’s ability to generate prospects both in oil plays and in other commodities, such as helium.

Corporate Governance The Company’s Board members bring a number of skills to it in the areas of geology, engineering and financial/capital markets. The Board and senior management meet quarterly, and as and when required, to consider and if appropriate, approve the strategic direction of the Company, its financial forecasts and budget, and its financial performance. In addition, the outside Directors (the majority of which are independent to management) comprise both standing Audit and Compensation Committees. Keystone has a talented employee and management team with expertise in accounting, engineering, land and land administration. We continue to utilize key members of Villanova 4 Oil Corp. (“V4”) to provide geological and geophysical expertise, together with supplementing our remaining administrative requirements. I would like to thank our Board and our employees and consultants, for their leadership and commitment to our Company. On behalf of the Board of Directors,

E. Craig Lothian, President/CEO & Chairman May 1, 2017


Property Review During 2016, Keystone continued to be proactive in generating activity on its mineral title and leasehold interests, including the drilling of a 100% Keystone operated horizontal well at Cantal South. The Company was also pursuing growth opportunities by way of acquisition. Acquisitions during the year resulted in Keystone acquiring interests in an additional 3,760 gross acres of fee mineral title lands. Although overall industry activity remained down in 2016, exploration and development continued in SE Saskatchewan. Crescent Point continues to be our lead operator, drilling 18 (2015 - 18) wells on Keystone lands in 2016, comprising 67% (2015 - 95%) of all drilling activity. Crescent Point accounted for 54% (2015 - 50%) of all royalty revenue paid to Keystone in 2016.

Operational Areas

The Keystone land base is well-diversified, with extensive lands throughout the conventional Mississippian production areas and the Viewfield Bakken play. Drilling activity on Keystone lands in 2016 saw a shift back to a balance of Mississippian targets, with 12 (2015 - 5) wells completed in 2015, and Bakken targets, with 15 (2015 - 14) wells drilled into this regionally extensive zone. The increase in Mississippian focus is a result of operators focusing on capital


efficiency, low risk, premium assets and an increase in exploration. Keystone had 4 (2015 – 0) exploration wells drilled on its lands in 2016. Keystone had 11 (Q1 2016 - 1) new wells drilled on its lands in the first quarter of 2017 with 9 (Q1 2016 - 4) additional well locations licensed to date. Not included in the map above, the Company acquired 265,000 gross acres under six helium exploration permits in Southern Saskatchewan (the “Helium Permits”). The Company has since divested two of the Helium Permits for cash consideration of $250,000 and a gross overriding royalty carried on 55,000 acres.

Viewfield Bakken Area Lands

In 2016, industry drilling activity on Keystone lands situated in the regional Bakken trend was restricted to infill drilling and secondary recovery methods such as water or gas floods. In 2016, 15 (2015 – 14) new Bakken horizontal wells were drilled on our lands in this area. Initial 90 day production rates for these wells averaged 95 Bopd.

At present, we anticipate up to 7 new Bakken wells being drilled in 2017 on our lands. Most of those being low risk in-fill wells in the Viewfield area.


Cantal South

In September of 2016, Keystone drilled its third 100% operated well at Cantal South (“1-19”). 1-19 averaged 107 Bopd over its first 30 days of production and is currently producing at 100 Bopd. Total Cantal South production is currently averaging in excess of 160 Bopd. The Company has further development plans in the Cantal South area. Keystone has agreed to participate on a non-operated basis in a well proximal to our existing leasehold lands (the “Partner Well”). We have also agreed to utilize the excess capacity at our battery to process fluids from the Partner Well. Keystone will in turn generate fluid processing revenue from our partner’s produced volumes. To the end of 2016, Keystone has incurred $6.16 million in capital costs at Cantal South and generated $5.22 million in net operating revenue.


Management’s Discussion and Analysis

ADVISORIES

The following management discussion and analysis (“MD&A”) dated May 1, 2017 is provided by the management of Keystone Royalty Corp. (“Keystone” or the “Company”). This MD&A supplements the disclosures in our reviewed financial statements which have been prepared according to Canadian Accounting Standards for Private Enterprises (“ASPE”) as at and for the year ended December 31, 2016. Certain information presented in this MD&A is of a forward looking nature. Such forward looking information involves substantial known and unknown risks and uncertainties. Most of these are beyond Keystone’s control and include: the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, the availability of qualified personnel and services, and the access to sufficient capital from internal and external sources. The reader is cautioned that assumptions used in the preparation of such information, while considered reasonable by Keystone at the time, may prove to be incorrect. Keystone’s actual results could differ materially from those expressed in, or implied by, such forward looking information.

BUSINESS OVERVIEW Keystone is a privately-held corporation incorporated under the laws of the Province of Saskatchewan. Our primary focus is acquiring and managing interests in mineral properties either through direct ownership of the fee title or by way of a lease or royalty interest. We receive revenue by leasing out our properties and where development has occurred, from royalties. In addition, we periodically acquire or participate in the exploration and development of our lands, and in those cases (where successful) we receive revenue on the direct sale of oil and gas.


RESULTS OF OPERATIONS

Production Volumes

Year ended Dec. 31 2016 2015 Royalty production Oil & NGL (Bbl) 174,675 198,937 Gas (Mcf) 346,490 226,234 Working interest production Oil & NGL (Bbl) 55,267 50,802 Gas (Mcf) 342 615 % Oil and NGL 80% 87% Royalty production Oil & NGL (Bopd) 479 545 Gas (Boepd) 158 103 Working interest Oil & NGL (Bopd) 151 139 Gas (Boepd) 0 1 Total production (Boepd) 788 788

As Keystone is primarily a royalty collector, we have very limited operational control over our production volumes. In 2016, our production volumes remained flat as acquisitions and drilling activity offset base production declines. Royalty interests comprised 81% of total volumes produced in 2016. In 2016, 27 new wells were drilled on the Company’s lands (19 in 2015), all of which have now been completed and put on production. At the Cantal South property, due to competitive drainage, we drilled an additional horizontal well in 2016. The property contributed 96% of 2016 working interest production.

Pricing

Average Benchmark Pricing 2016 2015 WTI benchmark price (US$/Bbl) 43.32 48.80 Exchange - US$/CDN$ 0.76 0.78 Canadian Light Sweet benchmark (CDN$/Bbl) 52.80 57.45 AECO natural gas (CDN$/Mcf) 2.18 2.70

The average selling prices received by Keystone reflect product quality, foreign exchange and transportation adjustments from benchmark prices.

Average Realized Pricing 2016 2015 Oil (CDN$/Bbl) 48.41 51.14 NGL (CDN$/Bbl) 26.03 22.43 Natural Gas (CDN$/Mcf) 2.18 2.71 Oil equivalent (CDN$/Boe) 39.72 48.13


In 2016, the Company’s average realized price per Bbl decreased 5% in comparison to 2015, as the average WTI price per Bbl dropped 11%. The decrease in the average WTI price per Bbl was tempered by a 3% reduction in the foreign exchange rate. Our production continues to remain unhedged in 2017, and we have no plans to enter into any foreign currency or commodity price hedges at this time.

Funds Generated by Operations

Year ended Dec. 31 2016 2015 Funds generated by operations $ 8,496,949 $ 10,355,674 Per Boe $ 29.53 $ 36.00 Per Share (basic) $ 1.06 $ 1.31

Keystone defines funds generated by operations as revenues less royalties, production expenses, general and administrative expenses, interest expenses, and current income taxes. Management utilizes funds generated by operations as a key measure to assess the ability of the Company to finance operating activities, capital expenditures, dividends and debt repayments. Operating Income

Year ended Dec. 31 2016 2015 Royalty income $ 8,700,628 $ 11,096,956 Bonus consideration 112,546 144,931 Oil & gas sales 2,728,658 2,742,827 Production expenses (1,156,761) (894,185) Total operating income $ 10,385,071 $ 13,090,529

Operating netback (per Boe) 2016 2015 Average realized price (CDN$) $ 39.72 $ 48.13 Bonus consideration 0.39 0.50 Production expenses (4.02) (3.11) Total operating netback $ 36.09 $ 45.52

The advantage of royalty ownership is the ability to benefit from the development of your lands without exposure to the capital expenditures, operating costs and environmental obligations generally associated with production of oil and natural gas assets. This “royalty advantage” provides the Company with high operating netbacks, consistent revenue from a diversified group of industry operators and low risk operations. In 2016, despite production volumes remaining flat year over year, the Company realized a 21% decrease in total operating income as the average realized price per Boe dropped 17% and production expenses increased 29%.


Investment Income and other

Year ended Dec. 31 2016 2015 Dividend income $ 27,900 $ 44,787 Lease rentals/shut in payments/other 74,543 117,341 Interest income - 111,097 Total investment income and other $ 102,443 $ 273,225

During the year, the Company received dividends on its shares of Crescent Point. Crescent Point reduced its monthly dividend from $0.10 per share to $0.03 per share effective April, 2016. In 2016, the Company realized a moderate decrease in lease rentals, shut in payments and other income, reflective of market conditions. The Company carried a balance on its operating demand loan throughout the year, so no interest income was earned in the year. Other Income

Year ended Dec. 31 2016 2015 Gain on sale of investments $ 102,669 $ 137,425 Fair value loss on investments $ (9,826) $ (583,938) Impairment of private investments $ - $ (762,335)

In 2016, the Company realized a gain on sale of investments of $102,669, resulting from the sale of Crescent Point shares in the year. In accordance with ASPE, public market securities were adjusted to fair value at year end and private investments were tested for impairment. As at December 31, 2016, the Company held 40,000 shares of Crescent Point and 2,713,814 shares of V4. At year end, the Company elected to record a deemed disposition of its 130,456 shares of Lightstream, after Lightstream commenced proceedings under the Companies’ Creditors Arrangement Act effective September 19, 2016.

Depletion, Depreciation and Accretion

Year ended Dec. 31 2016 2015 Depletion, depreciation & accretion $ 3,449,896 $ 3,207,418 Per Boe $ 11.99 $ 11.15

Depletion is a non-cash item which estimates the amount of capital expense attributable to each Boe produced, multiplied by the number of Boes produced in the year. It is anticipated that the depletion rate will increase moderately in 2017 as Management anticipates reduced drilling activity on our land to offset the typically high decline rates associated with SE Saskatchewan production.


General and Administrative Expenses

The main component of G&A expenses continues to be salaries and management support fees paid to V4, amounting to 79% of total G&A. The balance of the Company’s G&A costs are comprised of software fees, directors’ fees, bank and financing fees, review fees, donations and staff expenses. G&A decreased 18% compared to 2015, as the Company initiated a number of cost cutting measures in response to the challenging oil price environment. Approximately 40% of the savings resulted from having no lease costs associated with the Company’s head office location after acquiring KVL Properties Inc. (“KVL”) in 2015. Interest

Interest expense increased 59% in the year as the Company carried an outstanding balance on its revolving operating demand loan throughout the year. The interest rate, on the revolving operating demand loan, ranges from prime plus 0.50% to 2.50% based on a calculation of net debt to cash flow. As the net debt to cash flow never exceeded the minimum threshold, the effective rate for the year was prime plus 0.50%.

Stock Based Compensation

Year ended Dec. 31 2016 2015 Stock based compensation $ 312,391 $ 269,428 Per Boe $ 1.09 $ 0.94

Stock based compensation is an estimate of the non-cash cost of stock options outstanding in 2016 using guidance from the CPA Canada Handbook for fair valuing options granted by a non-public enterprise. In accordance with the CPA Canada Handbook, the Company determines the fair value of stock options on their grant date and records this amount as compensation expense over the period that the stock options vest, with a corresponding increase to contributed surplus. Upon the exercise of stock options, consideration received together with amounts previously recorded in contributed surplus is recorded as an increase in share capital.

Current Income Taxes

Year ended Dec. 31 2016 2015 Current income taxes $ 593,316 $ 1,386,244 Per Boe $ 2.06 $ 4.82

Year ended Dec. 31 2016 2015 G&A expenses $ 1,247,970 $ 1,527,832 Per Boe $ 4.34 $ 5.31

Year ended Dec. 31 2016 2015 Interest expenses $ 149,279 $ 94,004 Per Boe $ 0.52 $ 0.33


The corporate income tax rate applicable to 2016 was 27% (27% in 2015). Taxable income is based on total income and expenses reduced by claims for both accumulated tax pools and tax pools associated with current year capital expenditures. As the Company has limited tax pools available to offset its revenue generating capabilities, management expects income taxes to continue to be significant going forward. In 2016, the Company elected to record a deemed disposition of the shares held of Lightstream. This resulted in a $455,773 capital loss carry back.

Future Income Taxes

Year ended Dec. 31 2016 2015 Future income taxes $ 1,291,487 $ 598,202 Per Boe $ 4.49 $ 2.08

Future income taxes result from timing differences between Keystone’s taxable income and accounting income. As at December 31, 2016, the Company had approximately $53.2 million of tax pools available to reduce future taxable income.

Year ended Dec. 31 2016 2015 COGPE $ 36,090,922 $ 40,174,099 CDE 9,394,016 9,986,702 CEE 5,603,552 5,603,552 UCC 2,121,566 2,462,783 Total $ 53,210,056 $ 58,227,136

In 2012, the Company acquired $19.2 million of successor tax pools as part of the Equal Energy Ltd. (“Equal Energy”) fee titles acquisition. The successor tax pools can only be used to reduce taxable income on income generated from the Equal Energy properties. As at December 31, 2016, 100% of the CEE & 86% of the CDE are designated as successor tax pools.

SHARE CAPITAL & DIVIDENDS

Shares Outstanding

Year ended Dec. 31 2016 2015 Basic shares - Class A 8,022,167 7,891,554 Stock options 677,000 672,000 Diluted shares 8,699,167 8,563,554

Over the course of 2016, 160,000 options were exercised, resulting in 130,613 Class A shares being issued from treasury. Some Optionees elected to receive the net amount of Optioned Shares he/she was entitled to, based on the difference between the (adjusted) Exercise Price and the Fair Market Value of the Optioned Shares being exercised, as more particularly set out in Section 3.01 of the Plan. The Company granted an additional 165,000 stock options to current employees and directors.


Dividends

Year ended Dec. 31 2016 2015 Dividends $ 5,543,680 $ 11,610,690 Dividends per share (basic) $ 0.70 $ 1.50

The Company paid a $0.25 per share dividend in Q1 2016. The quarterly dividend was reduced to $0.15 per share for the balance of the year, in response to sustained weakness in oil prices. Effective January 1, 2017, based on current and forecast oil prices, the Company increased its quarterly dividend to $0.20 per share.

CAPITAL EXPENDITURES

Year ended Dec. 31 2016 2015 Land costs $ 213,498 $ 17,170,710 Drilling, completing, and equipping 1,057,298 40,589 Facilities 74,465 1,846,605 Total $ 1,345,261 $ 19,057,904

In 2016, the Company was unable to close any material property acquisitions. The majority of capital spent was on our 100% working interest property at Cantal South where we drilled an additional horizontal well.

GUIDANCE FOR 2017

Key Operating Assumptions

The Company’s budget for 2017 is as follows:

Variable Budget Average daily production (Boe) 813.6 Benchmark WTI price (US$/Bbl) 47.81 FX Rate (US$/CDN$) 0.75 Capital expenditures ($) 2,000,000 Funds generated by operations ($) 9,771,032


REVIEW ENGAGEMENT REPORT

To the Shareholders of Keystone Royalty Corp.:

We have reviewed the non-consolidated balance sheet of Keystone Royalty Corp. as at December 31,

2016 and the non-consolidated statements of income and retained earnings and cash flows for the year

then ended. Our review was made in accordance with Canadian generally accepted standards for review

engagements and, accordingly, consisted primarily of inquiry, analytical procedures and discussion

related to information supplied to us by the Company.

A review does not constitute an audit and, consequently, we do not express an audit opinion on these non-

consolidated financial statements.

The reserve information necessary to calculate depletion, depreciation, and accretion using the unit-of-

production method, including an amount for restoration and abandonment costs, is not readily available.

Had the information been available to complete our review, we might have determined adjustments to be

necessary to petroleum and natural gas properties, depletion and depreciation, and net income.

Except for the effect of adjustments, if any, which we might have determined to be necessary had we

been able to complete our review of depletion, depreciation, and accretion as described in the previous

paragraph, nothing has come to our attention that causes us to believe that these non-consolidated

financial statements are not, in all material respects, in accordance with Canadian accounting standards

for private enterprises.

Chartered Professional Accountants

Regina, Saskatchewan

March 23, 2017


KEYSTONE ROYALTY CORP. Non-consolidated Balance Sheet As at December 31, 2016 (Unaudited)

2016 2015

Assets Current assets: Cash (note 3) $ 293,105 $ 123,468 Accounts receivable 2,060,698 1,900,173 Income taxes recoverable 393,732 588,757 Prepaids 20,595 - 2,768,130 2,612,398 Investments (note 4) 730,000 839,919 Investment in KVL Properties Inc. (note 5) 1,000,000 1,000,000 Investment in Villanova 4 Oil Corp. (note 6) 1,085,526 585,526 Property, plant and equipment (note 7) 57,769,371 59,978,197 Future income taxes - 519,165

$ 63,353,027 $ 65,535,205

Liabilities and Shareholders' Equity Current liabilities: Accounts payable and accrued liabilities (note 8) $ 525,514 $ 204,552 Bank indebtedness (note 9) 3,400,000 5,450,000 3,925,514 5,654,552 Asset retirement obligation (note 10) 424,611 353,802 Future income taxes 772,322 -

5,122,447 6,008,354

Shareholders' equity: Share capital (note 11(b)) 30,707,741 29,923,141 Contributed surplus (note 11(d)) 834,816 908,025 Retained earnings 26,688,023 28,695,685

58,230,580 59,526,851 $ 63,353,027 $ 65,535,205

See accompanying notes to non-consolidated financial statements. On behalf of the Board:

__________________________ Director

_____________________________ Director


KEYSTONE ROYALTY CORP. Non-consolidated Statement of Income and Retained Earnings Year ended December 31, 2016 (Unaudited)

2016 2015 Revenue:

Royalty income $ 8,700,628 $ 11,096,956

Bonus consideration 112,546 144,931

Oil and gas sales 2,728,658 2,742,827

Investment income and other 102,443 273,225

11,644,275 14,257,939 Expenses:

Depletion, depreciation and accretion 3,449,896 3,207,418

General and administrative 1,247,970 1,527,832

Interest 149,279 94,004

Production 1,156,761 894,185

Stock based compensation (note 11(d)) 312,391 269,428

6,316,297 5,992,867

Income before the undernoted items and income taxes 5,327,978

8,265,072

Other income (expenses):

Realized gain on sale of investments (note 12) 102,669 137,425

Unrealized fair value loss on investments (9,826) (583,938)

Impairment of private investments - (762,335)

Income before income taxes 5,420,821 7,056,224 Income taxes:

Current 593,316 1,386,244

Future 1,291,487 598,202

1,884,803 1,984,446

Net income 3,536,018 5,071,778 Retained earnings, beginning of year 28,695,685 35,234,597 Dividends (5,543,680) (11,610,690) Retained earnings, end of year $ 26,688,023 $ 28,695,685

See accompanying notes to non-consolidated financial statements.


KEYSTONE ROYALTY CORP. Non-consolidated Statement of Cash Flows Year ended December 31, 2016 (Unaudited)

2016 2015

Cash provided by (used in): Operations: Net income $ 3,536,018 $ 5,071,778 Items not involving cash:

Depletion, depreciation and accretion 3,449,896 3,207,418 Stock based compensation 312,391 269,428 Realized gain on sale of investments (102,669) (137,425) Unrealized fair value loss on investments 9,826 583,938 Impairment of private investments - 762,335 Future income taxes 1,291,487 598,202

Change in non-cash working capital:

Accounts receivable (160,525) 318,019

Prepaids (20,595) -

Accounts payable and accrued liabilities 320,962 (255,733)

Income taxes recoverable 195,025 533,728

8,831,816 10,951,688 Financing:

(Decrease) increase in bank indebtedness (2,050,000) 5,450,000

Proceeds on share options exercised 399,000 606,500

Dividends paid (5,543,680) (11,610,690)

(7,194,680) (5,554,190) Investing:

Purchase of investments (1,293,030) (1,051,188)

Proceeds of sale of investments 995,792 -

Purchase of property, plant and equipment (1,345,261) (19,057,904)

Proceeds on sale of property, plant and equipment 175,000 -

(1,467,499) (20,109,092) Increase (decrease) in cash 169,637 (14,711,594)

Cash, beginning of year 123,468 14,835,062

Cash, end of year $ 293,105 $ 123,468

See accompanying notes to non-consolidated financial statements.

KEYSTONE ROYALTY CORP. Notes to Non-consolidated Financial Statements Year ended December 31, 2016 (Unaudited)


1. Nature of operations:

Keystone Royalty Corp. (the "Company'") is incorporated under the Business Corporations Act of

Saskatchewan. The Company is primarily engaged in acquiring and managing oil and gas royalty

assets.

The Company’s principal place of business is located at 2530 Sandra Schmirler Way, Regina,

Saskatchewan, Canada, S4W 0M7.

2. Significant accounting policies:

These financial statements are prepared in accordance with Canadian accounting standards for

private enterprises, with the Company electing to report on a non-consolidated basis.

The Company's significant accounting policies are as follows:

(a) Joint interest activities:

Certain areas of the Company's exploration, development and production activities are

conducted jointly with others. These non-consolidated financial statements reflect only the

Company's proportionate interest in such activities.

(b) Property, plant and equipment:

The Company follows the full cost method of accounting for petroleum and natural gas

operations whereby all costs of acquiring, exploring and developing oil and natural gas

properties and related reserves are capitalized. Such capitalized costs include land

acquisitions, geological and geophysical expenditures, lease rentals on non-producing

properties, expenditures of drilling both productive and non-productive wells, production

equipment, asset retirement costs and the portion of general and administrative expenses

directly attributable to exploration and development activities.

The costs of acquiring and evaluating unproved properties are initially excluded from depletion

calculations. These properties are assessed periodically to ascertain whether impairment has

occurred. When proved reserves are assigned or the property is considered to be impaired, the

cost of the property or the amount of impairment is added to the costs subject to depletion.

Capitalized costs, plus estimated future development expenditures associated with proved

reserves, are recognized as costs subject to depletion and depreciation expense using the

unit-of-production method based on estimated proved reserves. For the purposes of this

calculation, natural gas reserves and production volumes are converted to equivalent volumes

of oil based on the energy equivalency ratio of six thousand cubic feet of natural gas to one

barrel of oil.



The Company places a limit on the carrying value of petroleum, natural gas and other properties

and equipment, which may be depleted against revenues of future periods (the "ceiling test").

The carrying value is assessed to be recoverable when the sum of the present value of future

cash flows expected to be derived from production of proved reserves, the lower of cost and

market of unproved properties and the cost of major development projects exceeds the carrying

value. When the carrying value is not assessed to be recoverable, an impairment loss is

recognized to the extent that the carrying value of assets exceeds the sum of the present value

of future cash flows expected to be derived from production of proved reserves, the lower of

cost and market of unproved properties and the cost of major development projects.

Proceeds from the sale of properties are applied against capitalized costs, without recognizing

any gain or loss, unless such a sale would significantly alter the rate of depletion and

depreciation by more than 20%.

(c) Revenue recognition:

Revenue is made up of royalty income, working interest sales, bonus consideration and other

income earned during the period. Royalty income and working interest sales represent the sale

of crude oil, natural gas, natural gas liquids and other products.

Royalty income is recognized as it accrues upon the terms of the underlying royalty contracts.

Generally these contracts provide a monthly calculation of the royalties due based on a

percentage of production revenue.

Working interest sales are recognized as it accrues based on the underlying working interest

agreements.

(d) Asset retirement obligations:

The Company recognizes a future asset retirement obligation as a liability in the year in which it

incurs a legal obligation associated with the retirement of tangible long-lived assets that results

from the acquisition, construction, development and/or normal use of the assets based on the

best estimate of the expenditure required to settle the obligation. The Company concurrently

recognizes a corresponding increase in the carrying amount of the related long-lived asset that

is amortized over the life of the asset. The amount of the asset retirement obligation is

estimated using the expected cash flow approach that reflects a range of possible outcomes

discounted at a risk-free interest rate based on management's best estimate. Subsequent to

the initial measurement, the asset retirement obligation is adjusted at the end of each year to

reflect the passage of time and changes in the estimated future cash flows underlying the

obligation. Changes in the obligation due to the passage of time are recognized in income as

an operating expense using the interest method. Changes in the obligation due to changes in

estimated cash flows are recognized as an adjustment of the carrying amount of the related

long-lived asset that is amortized over the remaining life of the asset.



(e) Future income taxes:

The Company uses the asset and liability method of accounting for income taxes. Under the

asset and liability method, future tax assets and liabilities are recognized for the future tax

consequences attributable to differences between the financial statement carrying amount of

existing assets and liabilities and their respective tax bases. Future tax assets and liabilities are

measured using enacted or substantively enacted tax rates expected to apply to taxable income

in the years in which those temporary differences are expected to be recovered or settled. The

effect on future tax assets and liabilities of a change in tax rates is recognized in earnings in the

year that includes the date of enactment or substantive enactment. Refundable taxes that will

be recovered on the payment of qualifying dividends are recognized as a future income tax

asset.

(f) Stock-based compensation: The Company has a stock-based compensation plan consisting of stock options and share

appreciation rights which is described in note 11(c). Stock options and share appreciation rights

granted to directors, officers and employees are accounted for in accordance with the calculated

value method of accounting for stock-based compensation. The Company determines the fair

value of stock options on their grant date and records this amount as compensation expense

over the period that the stock options vest, with a corresponding increase to contributed surplus.

Upon the exercise of stock options, consideration received together with amounts previously

recorded in contributed surplus is recorded as an increase in share capital.

(g) Financial instruments:

Financial instruments are recorded at fair value on initial recognition. Freestanding derivative

instruments that are not in a qualifying hedging relationship and equity instruments that are

quoted in an active market are subsequently measured at fair value. All other financial

instruments are subsequently recorded at cost or amortized cost, unless management has

elected to carry the instruments at fair value.

Transaction costs incurred on the acquisition of financial instruments measured subsequently at

fair value are expensed as incurred. All other financial instruments are adjusted by transaction

costs incurred on acquisition and financing costs, which are amortized using the straight-line

method.

Financial assets are assessed for impairment on an annual basis at the end of the fiscal year, if

there are indicators of impairment. If there is an indicator of impairment, the Company

determines if there is a significant adverse change in the expected amount or timing of future

cash flows from the financial asset. If there is a significant adverse change in the expected

cash flows, the carrying value of the financial asset is reduced to the highest of the present

value of the expected cash flows, the amount that could be realized from selling the financial

asset or the amount the Company expects to realize by exercising its right to any collateral. If

events and circumstances reverse in a future period, an impairment loss will be reversed to the



extent of the improvement, not exceeding the initial carrying value.

3. Cash:

Cash is deposited in financial institutions with a strong investment grade rating.

(h) Use of estimates and measurement uncertainty:

The preparation of financial statements in conformity with Canadian accounting standards for

private enterprises requires management to make judgments, estimates and assumptions that

affect the application of accounting policies and the reported amounts of assets, liabilities,

income and expenses. Actual results may differ from these estimates.

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to

accounting estimates are recognized in the year in which the estimates are revised and in any

future years affected. Items that required significant estimates and judgments to be made by

management in the preparation of these non-consolidated financial statements are outlined

below.

Amounts recorded for depletion and depreciation of petroleum and natural gas properties, asset

retirement obligations and the ceiling test are based on estimates of reserves, production rates,

oil and natural gas prices, future costs and other relevant assumptions.

Accounts receivable for royalty income and working interest sales are measured at the fair

value, using estimates, per the terms of various royalty interest and working interest

agreements.

Stock based compensation is subject to the estimation of what the ultimate payout will be using

the Black-Scholes pricing model which is based on significant assumptions such as expected

volatility, forfeiture rates and expected term.

The provision for income taxes is based on judgments in applying income tax law and

estimates on the timing, likelihood and reversal of temporary differences between the

accounting and tax bases of assets and liabilities.

These above estimates are subject to measurement uncertainty and changes in these

estimates could materially impact the non-consolidated financial statements of future periods.

(I) (i) Investment in subsidiary:

(II)

The Company's investment in its wholly-owned subsidiary, KVL Properties Inc., is accounted

for in these non-consolidated financial statements at cost. Earnings from the investment are

recognized only to the extent dividends are received or receivable.



The Company has the following investments:

December 31 2016

December 31 2015

Crescent Point Energy Corp. $ 730,000 $ 806,000

Lightstream Resources Ltd. - 33,919 $ 730,000 $ 839,919

The Company’s investments in public market securities are recorded at fair value.

Effective September 19, 2016, Lightstream Resources Ltd. (“Lightstream”) commenced proceedings

under the Companies’ Creditors Arrangement Act (the “CCAA”). On December 29, 2016,

Lightstream closed the sale of substantially all of the assets and business to a new company owned

by former holders of Lightstream’s 9.875% second lien secured notes. Under section 50(1) of the

Income Tax Act, Keystone has elected to record a deemed disposition of the shares held of

Lightstream at year end.

5. Investment in KVL Properties Inc.:

December 31 December 31

2016 2015

Common shares $ 1,000,000 $ 1,000,000

Effective September 30, 2015, the Company acquired a 100% ownership interest in KVL Properties

Inc. (“KVL”), a private company. KVL owns two office buildings situated on lands leased from the

Regina Airport Authority, one of which houses the Company’s head office.

As at December 31, 2016, KVL had $4,188,800 of debt outstanding on the two office buildings,

which is corporately guaranteed by the Company. The mortgage agreements have two years of

term remaining. The guarantee will only be called in case of loan default by KVL.

6. Investment in Villanova 4 Oil Corp.:

December 31 December 31

2016 2015

Common shares $ 1,085,526 $ 585,526

4. Investments:



The investment represents a 2.75% (2015 – 2.46%) interest in Villanova 4 Oil Corp. (“V4OC”), a

private company. The Company is related to V4OC through common management.

On March 31, 2016, the Company participated in a V4OC Unit offering, investing an additional

$500,000. Each Unit consisted of one Class A common share at a price of $0.40 per share and one

common share purchase warrant. Each warrant entitles the holder to purchase one additional share

at a price of $0.50 per share for a period of 24 months from the closing date.

7. Property, plant and equipment:

December 31, 2016

Cost

Accumulated amortization

Net book value

Petroleum, natural gas and other properties $ 74,887,867 $ 20,953,755 $ 53,934,112

Production equipment 4,650,703 815,444 3,835,259

$ 79,538,570 $ 21,769,199 $ 57,769,371

December 31, 2015

Cost

Accumulated amortization

Net book value

Petroleum, natural gas and other properties $ 74,029,976 $ 17,713,431 $ 56,316,545

Production equipment 4,275,195 613,543 3,661,652

$ 78,305,171 $ 18,326,974 $ 59,978,197

Land and seismic costs associated with unproven properties that were excluded from property costs

subject to depletion for 2016 totaled $41,668,772 (2015 - $42,629,673).

There were no general and administrative expenses capitalized during 2016 or 2015.

At December 31, 2016, the “ceiling test” calculation was based upon the present value of future cash

flows, estimated using internally generated reserves and third party forecast pricing.

8. Accounts payable and accrued liabilities:

The Company has $16,587 in government remittances included in accounts payable and accrued

liabilities for 2016 (2015 - $55,926).



9. Credit facility:

As at December 31, 2016, the Company had $3,400,000 drawn on a $19,000,000 revolving

operating demand loan at the National Bank of Canada with an interest rate ranging from prime plus

0.50% to 2.50% based on a calculation of net debt to cash flow (2015 – prime plus 1%). As the net

debt to cash flow ratio never exceeded the minimum threshold, the effect rate for the year was prime

plus 0.50%. The facility is secured by a general assignment of book debts, a $50,000,000 debenture

with a floating charge over all assets of the Company with a negative pledge and undertaking to

provide fixed charges on the Company's major producing petroleum properties at the request of the

lender, as well as an assignment of revenues and monies under material contracts, as applicable.

The Company is subject to certain reporting and financial covenants in its credit facility. At

December 31, 2016, the credit facility has a financial covenant to which the Company must maintain

an adjusted working capital ratio of not less than 1.00:1.00 at all times. The Company was in

compliance with all covenants as at December 31, 2016.

10. Asset retirement obligation:

The Company has recorded an asset retirement obligation with respect to its petroleum and natural

gas properties. The following table reconciles the Company's asset retirement obligation:

December 31

2016 December 31

2015

Balance, beginning of year $ 353,802 $ 179,815

Provisions made during the year 51,494 -

Accretion expense 7,671 8,563

Change in estimates 11,644 165,424

Balance, end of year $ 424,611 $ 353,802

The Company’s asset retirement obligations result from its ownership interest in petroleum and

natural gas properties. The total asset retirement obligation is estimated based on the Company’s

net ownership interest in all wells and facilities, estimated costs to reclaim and abandon these wells

and facilities and the estimated timing of the costs to be incurred in future years. The Company has

estimated the net present value of the asset retirement obligations to be $424,611 as at December

31, 2016 based on an undiscounted total future liability of $404,844. These payments are expected

to be made over the next 15 years with the majority of costs to be incurred between 2021 and 2029.

The discount factor, being the risk-free rate, is 1.80% (2015 - 2.02%). The liability has been

calculated using an inflation rate of 2.00% (2015 – 2.00%) and an undiscounted abandonment cost

per well of $50,000 (2015 - $50,000).



11. Share capital:

(a) Authorized:

The authorized share capital of the Company consists of an unlimited number of Class A voting

common shares, an unlimited number of Class B non-voting common shares, and an unlimited

number of Class C preferred shares.

(b) Issued and outstanding:

December 31, 2016 December 31, 2015 Class A Common Number Consideration Number Consideration

Balance, beginning of year 7,891,554 $ 29,923,141 7,710,241 $ 28,899,441

Issued on exercise of options 130,613 784,600 181,313 1,023,700 Balance, end of year 8,022,167 $ 30,707,741 7,891,554 $ 29,923,141

During the year 160,000 options were exercised, resulting in 130,613 Class A shares being issued

from treasury. Some Optionees elected to receive the net amount of Optioned Shares he/she was

entitled to based on the difference between the (adjusted) Exercise Price and the Fair Market Value

of the Optioned Shares being exercised, as more particularly set out in Section 3.01 of the Plan.

The Company paid a $0.25 per share dividend in Q1 2016. The quarterly dividend was reduced to

$0.15 per share for the balance of 2016, due to the weak oil price environment.

(c) Stock options:

The Company has a stock option plan to provide options for directors, officers, employees and

consultants to purchase common shares. The total aggregate amount of the stock options that can

be issued cannot exceed ten percent of the outstanding common shares.

The following table reconciles the changes in outstanding stock options:

December 31, 2016 December 31, 2015

Number Exercise Price Number Exercise Price

Outstanding, beginning of year 672,000 $ 7.57 570,000 $ 6.79

Granted 165,000 11.25 292,000 9.85

Exercised (160,000) 4.56 (190,000) 3.46

Outstanding, end of year 677,000 $ 8.48 672,000 $ 7.57

Exercisable, end of year 287,333 $ 7.14 290,000 $ 5.95

The stock options vest at a rate of one-third in each of the first three years from the date of issue. All

unexercised stock options will expire on the fifth anniversary from the date of issue. The stock option



plan also provides that the exercise price of any unexercised options (whether vested or not) shall be

reduced by the amount of cash dividends declared and payable subsequent to the date of the option

grant, however, in no event will the exercise price of any option be less than $0.01 per share.

The following table summarizes the expiry terms and exercise prices of the Company's 677,000

outstanding stock options as at December 31, 2016:

Number Weighted Number of stock average of stock Exercise options remaining options Price outstanding term (years) exercisable

$4.52 30,000 0.2 30,000 $6.70 100,000 1.1 100,000 $7.00 10,000 2.0 10,000 $7.00 80,000 2.1 53,333 $8.80 100,000 3.0 33,333 $8.30 192,000 3.8 64,000

$11.10 165,000 4.9 -

The per share fair value of the stock options granted during the year ended December 31, 2016 was

estimated based on the date of grant using the Black-Scholes option pricing model with the following

assumptions:

November 21 2016

Grant price per share $ 11.25 Risk free interest rate (%) 0.75 Expected life (years) 5 Expected volatility (%) 30.00 Expected dividends - Forfeitures - Grant-date fair value per share $ 3.11

(d) Contributed surplus:

December 31

2016 December 31

2015

Balance, beginning of year $ 908,025 $ 1,055,797

Stock-based compensation 312,391 269,428

Transfer to share capital upon exercise (385,600) (417,200)

Balance, end of year $ 834,816 $ 908,025



12. Gain on sale of investments:

The Company realized a gain on sale of investments of $102,669, resulting from a year over year net

disposition of 10,000 shares of Crescent Point Energy Corp. (“Crescent Point”). The Company

completed a number of buy/sell transactions throughout the year, reducing its taxable cost base on

Crescent Point held shares by $5.14 per share.

13. Related party transactions:

All related party transactions are in the normal course of operations and were measured at the

exchange amount.

Effective June 1, 2014, the Company entered into a Management Support Agreement with V4OC to

receive ongoing support services and agreed to pay the greater of $100,000 (2015 - $100,000) or

0.8% (2015 – 0.8%) of the Company’s gross annual operating revenue as compensation. In 2016, a

total of $100,000 (2015 - $112,816) has been incurred to V4OC under this agreement.

At December 31, 2016, the Company had accounts payable to V4OC of $21,144 (2015 - $51,603).

Effective September 30, 2015, the Company acquired 100% of the shares of KVL. KVL owns two

office buildings situated on lands leased from the Regina Airport Authority, one of which houses the

Company’s head office. The Company reimburses KVL for net operating costs and tenant expenses

associated with its head office operations. Starting in October 2015, the Company received free rent

for the head office from KVL.

At December 31, 2016, the Company had accounts payable to KVL of $5,099 (2015 - $5,841), and

accounts receivable of $30,000 (2015 - $nil).

The Company is also related to Lex Capital Corp. through common management and shareholders.

At December 31, 2016, the Company had accounts receivable from Lex Capital Corp. of $4,227

(2015 - $3,015).

14. Financial instruments:

(a) Commodity price and foreign exchange risk:

The nature of the Company's operations result in exposure to fluctuations in commodity prices

and exchange rates as crude oil and natural gas prices received are referenced to U.S. dollar

denominated prices. The Company monitors, and when appropriate, may use derivative

financial instruments to manage its exposure to these risks.

(b) Interest rate risk:

Interest rate risk is the risk that the value of a financial instrument might be adversely affected



by a change in the interest rates. Changes in market interest rates may have an effect on the

cash flows associated with some financial assets and liabilities, known as cash flow risk, and on

the fair value of other financial assets or liabilities, known as price risk.

The Company is exposed to interest rate cash flow risk with its credit facility as it is at a floating

rate of prime plus an applicable margin ranging from 0.50% to 2.50% based on a calculation of

net debt to cash flow.

(c) Credit risk management:

A substantial portion of the Company's accounts receivable are with customers and joint

venture partners in the oil and gas industry and are subject to normal industry credit risks.

Settlement terms are normally 30 days.

(d) Commodity price risks:

The Company has not undertaken any hedging activities.

(e) Credit concentration:

As at December 31, 2016, two customer’s accounted for 38% of accounts receivable. The

Company believes that there is no unusual exposure with the collection of these receivables.

15. Capital management:

The Company’s objectives when managing its capital are to maximize long-term shareholder value

and distribute a portion of excess cash while maintaining a level of financial flexibility which allows

the Company to take advantage of opportunities such as land sale acquisitions, and other

investment opportunities as they arise. The Company manages its capital structure and adjusts it as

a result of changes in economic conditions and the risk characteristics of the underlying petroleum

and natural gas assets. The Company considers its capital structure to include shareholders’ equity,

the available credit line, and working capital. In order to maintain or adjust the capital structure, the

Company may from time to time issue shares, adjust its capital spending or suspend or reduce

dividend rates to manage current or forecasted debt levels.

There were no changes in the Company’s approach to capital management during the year.

16.

Comparative figures:

Certain comparative figures have been reclassified to conform with current year presentation.

17.

Change in accounting policy:

Effective January 1, 2016, the Company adopted CPA Canada Handbook Section 1591

Subsidiaries. There was no impact to the financial statements upon adoption of this section.


Corporate Directory

HEAD OFFICE 2530 Sandra Schmirler Way Regina, SK S4W 0M7 Telephone: (306) 790-4151 Fax: (306) 789-5656 www.keystone-group.ca

ADMINISTRATIVE & TECHNICAL SUPPORT Villanova 4 Oil Corp. 2530 Sandra Schmirler Way Regina, SK S4W 0M7

MANAGEMENT TEAM

E. Craig Lothian President and CEO John Benson Chief Financial Officer Andrew Spagrud Mgr., Engineering and Development Gabrielle Schubach Accountant Kimberly Burke Land Administrator Jesse Ross Accountant DIRECTORS James P. Baker(1&2) Regina, SK Greg Henders (2) Okotoks, AB E. Craig Lothian Regina, SK Bruce W. Wilson (1) Regina, SK 1) Member of the Audit Committee 2) Member of the Compensation Committee

FINANCIAL INSTITUTION

National Bank of Canada

Calgary, AB LEGAL COUNSEL MLT Aikins LLP Regina, SK/Calgary, AB

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