CALGARY, Alberta, Nov. 14, 2018 (GLOBE NEWSWIRE) — Freehold Royalties Ltd. (Freehold) (TSX:FRU) announced third quarter results for the period ended September 30, 2018.

RESULTS AT A GLANCE

	Three Months Ended					Nine Months Ended
	September 30					September 30
FINANCIAL ($000s, except as noted)	2018	2017		Change		2018	2017	Change
Royalty and other revenue	40,815	33,938		20	%	120,334	113,459	6	%
Net income	8,389	103		–		18,198	20,275	-10	%
Per share, basic and diluted ($)	0.07	–		–		0.15	0.17	-12	%
Funds from operations	35,900	27,927		29	%	102,824	91,765	12	%
Per share, basic ($)	0.30	0.24		25	%	0.87	0.78	12	%
Operating income (1)	39,225	31,246		26	%	115,214	103,565	11	%
Operating income from royalties (%)	99	99		–		99	95	4	%
Acquisitions	17,915	(146	)	–		51,493	34,473	49	%
Working interest dispositions	1	2,969		–		8,138	32,065	-75	%
Dividends declared	18,634	17,714		5	%	55,285	50,757	9	%
Per share ($) (2)	0.1575	0.15		5	%	0.47	0.43	9	%
Net debt	78,657	38,274		106	%	78,657	38,274	106	%
Shares outstanding, period end (000s)	118,348	118,128		–		118,348	118,128	–
Average shares outstanding (000s) (3)	118,293	118,073		–		118,239	118,016	–
OPERATING
Royalty production (boe/d) (4)	10,322	10,919		-5	%	10,854	10,964	-1	%
Total production (boe/d) (4)	11,002	12,036		-9	%	11,572	12,456	-7	%
Oil and NGL (%)	54	56		-4	%	54	56	-4	%
Average price realizations ($/boe) (4)	38.95	29.67		31	%	36.76	32.54	13	%
Operating netback ($/boe) (1) (4)	38.74	28.22		37	%	36.47	30.46	20	%

(1) See Non-GAAP Financial Measures.
(2) Based on the number of shares issued and outstanding at each record date.
(3) Weighted average number of shares outstanding during the period, basic.
(4) See Conversion of Natural Gas to Barrels of Oil Equivalent (boe).

President’s Message

Stronger crude prices and lower cash costs drove third quarter growth in Freehold’s funds from operations. Reflecting lower volumes year to date, we are revising our 2018 production guidance by 4% to a range of 11,250-11,500 boe/d. Reduced volumes are associated with lower third-party production additions, natural gas and heavy oil curtailments and fewer audit recoveries. We will continue to monitor industry activity and will provide 2019 guidance as part of our fourth quarter results.

Looking forward, we anticipate some near-term headwinds associated with Canadian energy, however, many of our prospects are light oil opportunities in Saskatchewan where pricing is better. As we saw in Q3-2018, we see more industry drilling occurring where there are lighter oil opportunities and the economics are superior.

As we have for the past 22 years, we will continue to strive to preserve our balance sheet and maintain an attractive dividend, thus providing investors with a lower risk oil and gas investment.

Tom Mullane
President and CEO  

Dividend Announcement

The Board has declared a dividend of $0.0525 per common share to be paid on December 17, 2018 to shareholders of record on November 30, 2018. The dividend is designated as an eligible dividend for Canadian income tax purposes.

2018 Third Quarter Highlights

Freehold delivered strong financial results in the third quarter of 2018. Highlights included:

• Funds from operations totaled $35.9 million, an increase of 29% compared to Q3-2017 and 4% versus the previous quarter. Higher funds from operations was largely driven by better oil and natural gas liquids (NGL) prices. On a per share basis, funds from operations was $0.30/share in Q3-2018 up from $0.24/share in Q3-2017 and $0.29/share in Q2-2018.
• Freehold’s royalty production averaged 10,322 boe/d, down 5% versus Q3-2017 and 7% when compared to Q2-2018. Reduced volumes are associated with lower third-party production additions, natural gas and heavy oil curtailments and fewer audit recoveries (75 boe/d in Q3-2018 versus 700 boe/d in Q3-2017). Historically, we have seen a slight drop in royalty production from Q2 to Q3 with a rebound in Q4.
• Royalty interests accounted for 94% of total production and contributed 99% of operating income in Q3-2018.
• Working interest production declined 39% to 680 boe/d in Q3-2018 relative to Q3-2017 largely due to dispositions, in-line with our strategy.
• Wells drilled on our royalty lands totaled 175 (6.3 net) in the quarter compared to 144 (6.4 net) in Q3-2017. Approximately 80% of non-unit activity was focused on our gross overriding royalty lands (GORR) lands while approximately 20% targeted prospects on our mineral title land. For the first nine months of 2018, 499 gross (13.9 net) wells have been drilled, compared to 352 gross (16.6 net) during the same period last year.
• Freehold generated $16.4 million in free cash flow ⁽¹⁾, over and above our dividend, which we applied to acquisitions completed during the quarter. At September 30, 2018, net debt totaled $78.7 million resulting in a net debt to funds from operations ratio of 0.6 times.
• Freehold allocated $17.9 million towards acquisition activities in Q3-2018. In August, Freehold closed the purchase of 64,000 acres of royalty lands with approximately 90 boe/d of production (one-third oil and NGL) across central Alberta and the Deep Basin for $5.9 million and the assignment of certain minor working interest assets. In September, Freehold closed the purchase of a GORR across 109,000 acres of land with prospectivity for the Clearwater formation in the Jarvie and Nipisi areas of Alberta for $12 million.
• In Q3-2018, Freehold issued 19 new lease agreements with 13 companies, compared to 18 issued in Q2-2018 and 30 leases in Q3-2017, highlighting the success of our leasing team. To September 30^th in 2018 (YTD) we have completed 95 new lease agreements on our royalty lands. Since the inception of our leasing team in January 2017 we have completed 195 new lease agreements.
• Cash costs ⁽¹⁾ for the quarter totaled $4.46/boe, down from $4.80/boe in Q3-2017. For 2018, we are forecasting cash costs of approximately $5.00/boe.
• Dividends declared for Q3-2018 totaled $0.1575 per share, up 5% versus the previous year. In March 2018, Freehold announced an increase to its monthly dividend from $0.05 to $0.0525 per share commencing in April 2018.
• Basic payout ratio ⁽¹⁾ (dividends declared/funds from operations) for Q3-2018 totaled 52% while the adjusted payout ratio ⁽¹⁾ ((cash dividends plus capital expenditures)/funds from operations) for the same period was 54%.

^{(1) See Non-GAAP Financial Measures}

Royalty Drilling

Including drilling associated with acquisitions and unit wells, 499 (13.9 net) wells were drilled on our royalty lands during the first nine months of 2018. This represents an increase of 42% on a gross basis and a 16% decline on a net measure versus the same period in 2017. As typical in the third quarter, we saw a rebound in activity on our royalty lands relative to Q2-2018.

Activity through the first nine months of 2018 was primarily focused on Saskatchewan oil projects. Drilling in the Viking at Dodsland and Mississippian carbonates in southeast Saskatchewan continue to lead activity in Saskatchewan. In Alberta, Cardium oil drilling continues to drive activity, with a recent uptick in Viking Oil development. In Q3-2018 19 gross Alberta Viking oil wells were drilled on our lands compared with six in the entire first half of 2018.  Industry drilled 131 gross wells on our non-unit lands in Q3-2018 (299 YTD) and 44 wells on our unit lands (200 YTD).  27 of those non-unit drills were on title land and 104 were on GORR lands.  Our top payors continue to represent some of the most well capitalized E&P companies in Canada.

ROYALTY INTEREST DRILLING

	Three Months Ended September 30				Nine Months Ended September 30
	2018		2017		2018		2017
		Equivalent		Equivalent		Equivalent		Equivalent
	Gross	Net (1)	Gross	Net (1)	Gross	Net (1)	Gross	Net (1)
Non-unitized wells	131	6.1	121	6.3	299	13.1	296	16.3
Unitized wells (2)	44	0.2	23	0.1	200	0.8	56	0.3
Total	175	6.3	144	6.4	499	13.9	352	16.6

(1) Equivalent net wells are the aggregate of the number obtained by multiplying each gross well by our royalty interest percentage.
(2) Unitized wells are in production units wherein we generally have small royalty interests in hundreds of wells.

Guidance Update

Below are details of some of the changes made to our key operating assumptions for 2018 based on results for the first nine months of the year and expectations for the remainder of the year. 

• We are revising our 2018 average production range downwards by 4% to 11,250-11,500 boe/d (previously 11,750-12,250 boe/d). There has been lower than expected production from royalty drilling, lower than typical additions from our audit function and production curtailments associated with weakness in natural gas and heavy oil pricing. Volumes are expected to be weighted approximately 54% oil and NGL and 46% natural gas. We continue to maintain our royalty focus with royalty production accounting for 94% of forecasted 2018 production and 99% of operating income.
• We are maintaining our 2018 drilling forecast of 20 net wells.
• We are maintaining our WTI oil price assumption of US$65.00/bbl. However, we have reduced our WCS price assumption to $50.00/bbl (previously $55.00/bbl) and our Edmonton Light Sweet price assumption to $70.00/bbl (previously $76.00/bbl), reflecting higher differentials caused by increasing Canadian production levels and limited takeaway capacity.
• We have reduced our AECO natural gas price assumption to $1.55/mcf (previously $1.75/mcf) reflecting lower than expected prices to date.
• Based on our current $0.0525/share monthly dividend level, we expect our 2018 adjusted payout ratio ((cash dividends plus capital expenditures)/funds from operations) to be approximately 64% (previously 55%).
• General and administrative costs remain at $2.50/boe.
• We have increased our forecast year-end net debt to funds from operations to approximately 0.8 times due to acquisitions completed and revisions to our production and pricing guidance.

Key Operating Assumptions

		Guidance Date
2018 Annual Average		Nov. 14, 2018	Aug. 2, 2018	May 9, 2018	Mar. 8, 2018
Total daily production	boe/d	11,250-11,500	11,750-12,250	11,750-12,250	11,750-12,250
West Texas Intermediate crude oil	US$/bbl	65.00	65.00	65.00	60.00
Edmonton Light Sweet crude oil	Cdn$/bbl	70.00	76.00	76.00	N/A
Western Canadian Select crude oil	Cdn$/bbl	50.00	55.00	53.00	45.00
AECO natural gas	Cdn$/Mcf	1.55	1.75	1.75	2.00
Exchange rate	Cdn$/US$	0.77	0.77	0.79	0.80
Operating costs	$/boe	1.45	1.45	1.45	1.45
General and administrative costs (1)	$/boe	2.50	2.50	2.50	2.50
Weighted average shares outstanding	millions	118	118	118	118

(1) Excludes share based compensation.

Recognizing the cyclical nature of the oil and gas industry, we continue to closely monitor commodity prices and industry trends for signs of changing market conditions. We caution that it is inherently difficult to predict activity levels on our royalty lands since we have no operational control. As well, significant changes (positive or negative) in commodity prices (including Canadian oil price differentials), foreign exchange rates, or production rates may result in adjustments to the dividend rate.

Based on our current guidance and commodity price assumptions, and assuming no significant changes in the current business environment, we expect to maintain the current monthly dividend rate through the next quarter. We will continue to evaluate the commodity price environment and adjust the dividend levels as necessary (subject to the quarterly review and approval of our Board of Directors).

Conference Call Details

A conference call to discuss financial and operational results for the period ended September 30, 2018 will be held for the investment community on Thursday, November 15, 2018 beginning at 7:00 am MT (9:00 am ET). To participate in the conference call, approximately 10 minutes prior to the conference call, please dial 1-800-806-5484 (toll-free in North America), participant access code 5263079#.

Availability on SEDAR

Freehold’s 2018 third quarter interim unaudited condensed consolidated financial statements and accompanying Management’s Discussion and Analysis (MD&A) are being filed today with Canadian securities regulators and will be available at www.sedar.com and on our website at www.freeholdroyalties.com.

Forward-looking Statements

This news release offers our assessment of Freehold’s future plans and operations as at November 14, 2018, and contains forward-looking statements that we believe allow readers to better understand our business and prospects. These forward-looking statements include our expectations for the following:

• our outlook for commodity prices including supply and demand factors relating to crude oil, heavy oil, and natural gas;
• light/heavy oil price differentials;
• changing economic conditions;
• cash costs forecasted at approximately $5.00/boe;
• continuing to monitor industry activity and our plan to provide 2019 guidance as part of our fourth quarter results;
• anticipating near-term headwinds associated with Canadian energy;
• many of our prospects being light oil opportunities in Saskatchewan where pricing is better;
• seeing more industry drilling occurring where there are lighter oil opportunities and the economics are superior;
• continuing to strive to preserve our balance sheet and maintain an attractive dividend, thus providing investors with a lower risk oil and gas investment;
• foreign exchange rates;
• drilling activity during 2018 and the impact on our production base;
• our expected adjusted payout ratio for 2018;
• average production for 2018, contribution from royalty lands and weighting of oil, NGL and natural gas;
• 2018 percentage of production and operating income from royalties;
• key operating assumptions including operating costs and general and administrative costs;
• forecast year-end net debt to funds from operations;
• industry drilling and development activity on our royalty lands, including our estimate of 2018 net royalty wells at 20;
• our dividend policy and expectations for future dividends; and
• maintaining our monthly dividend rate through the next quarter.

By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond our control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, royalties, environmental risks, taxation, regulation, changes in tax or other legislation, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility, and our ability to access sufficient capital from internal and external sources. Risks are described in more detail in our Annual Information Form available at www.sedar.com.

With respect to forward-looking statements contained in this news release, we have made assumptions regarding, among other things, future commodity prices, future capital expenditure levels, future production levels, future exchange rates, future tax rates, future legislation, the cost of developing and producing our assets, our ability and the ability of our lessees to obtain equipment in a timely manner to carry out development activities, our ability to market our oil and gas successfully to current and new customers, our expectation for the consumption of crude oil and natural gas, our expectation for industry drilling levels, our ability to obtain financing on acceptable terms, shut-in production, production additions from our audit function and our ability to add production and reserves through development and acquisition activities. The key operating assumptions with respect to the forward-looking statements referred to above are detailed in the body of this news release.

You are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Our actual results, performance, or achievement could differ materially from those expressed in, or implied by, these forward-looking statements. We can give no assurance that any of the events anticipated will transpire or occur, or if any of them do, what benefits we will derive from them. The forward-looking information contained in this document is expressly qualified by this cautionary statement. To the extent any guidance or forward looking statements herein constitute a financial outlook, they are included herein to provide readers with an understanding of management’s plans and assumptions for budgeting purposes and readers are cautioned that the information may not be appropriate for other purposes. Our policy for updating forward-looking statements is to update our key operating assumptions quarterly and, except as required by law, we do not undertake to update any other forward-looking statements.

You are further cautioned that the preparation of financial statements in accordance with International Financial Reporting Standards (IFRS), which are the Canadian generally accepted accounting principles (GAAP) for publicly accountable enterprises, requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. These estimates may change, having either a positive or negative effect on net income, as further information becomes available and as the economic environment changes.

Conversion of Natural Gas to Barrels of Oil Equivalent (BOE)

To provide a single unit of production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (boe). We use the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value.

Non-GAAP Financial Measures

Within this news release, references are made to terms commonly used as key performance indicators in the oil and natural gas industry. We believe that, operating income, operating netback, basic payout ratio, adjusted payout ratio, free cash flow and cash costs are useful supplemental measures for management and investors to analyze operating performance, financial leverage, and liquidity, and we use these terms to facilitate the understanding and comparability of our results of operations and financial position. However, these terms do not have any standardized meanings prescribed by GAAP and therefore may not be comparable with the calculations of similar measures for other entities.

Operating income, which is calculated as royalty and other revenue less royalties and operating expenses, represents the cash margin for product sold. Operating netback, which is calculated as average unit sales price less royalties and operating expenses, represents the cash margin for product sold, calculated on a per boe basis.

Payout ratios are often used for dividend paying companies in the oil and gas industry to identify its dividend levels in relation to the funds it receives and uses in its capital and operational activities. Basic payout ratio is calculated as dividends declared as a percentage of funds from operations. Adjusted payout ratio is calculated as dividends paid in cash plus capital expenditures as a percentage of funds from operations.

Free cash flow is calculated by subtracting capital expenditures from funds from operations. Free cash flow is a measure often used by dividend paying companies to determine cash available for payment of dividends, paying down debt or investment.

Cash costs is a total of certain cash expenses in the statement of income deducted in determining funds from operations. For Freehold cash costs are identified as royalty expense, operating expense, general and administrative expense, interest expense and share based compensation payments. It is key to funds from operations, representing the ability to, sustain dividends, repay debt and fund capital expenditures.

We refer to various per boe figures which provide meaningful information on our operational performance. We derive per boe figures by dividing the relevant revenue or cost figure by the total volume of oil, NGL and natural gas production during the period, with natural gas converted to equivalent barrels of oil as described above.

For further information related to these non-GAAP terms, including reconciliations to the most directly comparable GAAP terms, see our most recent MD&A.

For further information, contact:

Freehold Royalties Ltd.
Matt Donohue
Manager, Investor Relations and Capital Markets
t.  403.221.0833
f.  403.221.0888
tf. 1.888.257.1873
e.  [email protected]
w. www.freeholdroyalties.com