Freehold Royalties Ltd. Announces 2013 Third Quarter Results

CALGARY, ALBERTA–(Marketwired – Nov. 14, 2013) – Freehold Royalties Ltd. (Freehold) (TSX:FRU) announces third quarter results for the period ended September 30, 2013.

1. See Additional GAAP Measures and Non-GAAP Financial Measures.
2. Net of adjustments.
3. Based on the number of shares issued and outstanding at each record date.
4. Net debt as at September 30, 2013 was $41.7 million, down $8.9 million from $50.6 million at June 30, 2013.
5. Weighted average number of shares outstanding during the period, basic.
6. See Conversion of Natural Gas to Barrels of Oil Equivalent (boe).

November Dividend Announcement

The Board of Directors has declared the November dividend of $0.14 per share, will be paid on December 16, 2013 to shareholders of record on November 30, 2013. The dividend is designated as an eligible dividend for Canadian income tax purposes. Including the December 16, 2013 payment, the twelve-month trailing cash dividends total $1.68/share.

2013 Third Quarter Highlights

• Average production for the third quarter rose 1%, and average price realizations climbed 23%, resulting in a 23% increase in gross revenue compared to the third quarter of 2012.
• Compared to the third quarter of 2012, oil and NGL production declined 2% in the quarter, while natural gas volumes improved 5%. The third quarter included positive prior period adjustments to royalty production of approximately 200 boe/d, mainly due to our ongoing audit program.
• Royalty production was flat compared to the third quarter of 2012, averaging 5,863 boe/d (accounting for 67% of production), while working interest production gained 1%.
• Funds from operations totalled $36.4 million in the third quarter, up 39% from the same period last year, mainly due to higher realized liquids pricing. Net income of $19.0 million, represented a 58% improvement from the third quarter of 2012.
• Dividends for the third quarter of 2013 totalled $0.42 per share, unchanged from the prior year.
• Average participation in our DRIP was 32% (Q3 2012 – 25%). Cash retained totalled $20.3 million (first nine months of 2013) and continues to fund our capital program.
• Net capital expenditures on our working interest properties totalled $5.7 million over the quarter ($24.0 million for the year to date), with the majority invested on our mineral title lands.
• In September, we closed an acquisition in southeast Alberta for $2.3 million, including adjustments, weighted 78% royalty interest and 22% working interest. This transaction will result in additions to production of 36 boe/d, weighted 48% to oil.
• At September 30th, 2013, long term debt totalled $49.0 million, down from $55.0 million at June 30, 2013.
• Net debt as of the third quarter 2013 implied 0.3 times trailing funds from operations and net debt obligations represented approximately 12% of total capitalization.

Guidance Update

The table below summarizes our key operating assumptions for 2013, updated to reflect actual statistics for the first nine months and our current expectations for the remainder of the year. The changes reflect the following factors:

• Through 2013, we are now forecasting WTI prices to average $98.00/bbl and AECO $3.25/mcf, up slightly from our previous guidance forecast with the Cdn$/US$ exchange rate dropping to $0.97.
• Due to $2.5 million of acquisition activity in the third quarter and an additional $6.1 million in October, long term debt is expected to increase to $53 million.
• We have made no changes to our 2013 production forecast (8,800 boe/d). Volumes for 2013 are expected to be weighted approximately 64% oil and natural gas liquids (NGL) and 36% natural gas, similar to our current product mix. We continue to maintain our royalty focus with royalty production accounting for 70% of forecasted 2013 production.
• Accounting for increased well servicing and power costs we have increased our assumption for operating costs from $5.30 to $5.60/boe.
• We are maintaining our 2013 capital budget at $32 million. Capital investment in the fourth quarter is expected to total $8 million, with the majority of the focus centred on development activities in southeast Saskatchewan.

1. For a sensitivity analysis of the potential impact of key variables on funds from operations per share, see page 5 of our 2012 Annual MD&A.
2. Excludes share based and other compensation.
3. Assumes an average 25% participation rate in Freehold’s dividend reinvestment plan, which is subject to change at the participants’ discretion.
4. Corporate tax estimates will vary depending on commodity prices and other factors.

2014 Outlook

For 2014, the Board has approved a capital budget of $30 million. Our focus will continue to centre on oil development within our mineral title lands and includes approximately 49 gross (16 net risked) wells. Our spending will be comprised of approximately one-half to be deployed in southeast Saskatchewan (light oil), with the remaining balance allocated to our opportunity base in both the Lloydminster area (heavy oil) and Western Alberta (Cardium oil) plays. We maintain that capital may be adjusted as the year progresses, depending on the operating environment and individual well results.

Based on this level of capital investment, anticipated drilling activity by lessees on our royalty lands, and normal production declines (and excluding any potential acquisitions), we expect 2014 production to average approximately 8,600 boe/d. Volumes will be comprised of approximately 62% oil and NGL’s and 38% natural gas. We continue to maintain our royalty focus with royalty production expected to account for approximately 70% of forecasted 2014 production.

After paying a large lump sum ($46 million) associated with a previous two years tax burden in 2013, we expect our tax liability to normalize through 2014, at approximately 20% of pre-tax cash flow.

1. Excludes share based and other compensation.
2. Assumes an average 25% participation rate in Freehold’s dividend reinvestment plan, which is subject to change at the participants’ discretion.
3. Corporate tax estimates will vary depending on commodity prices and other factors.

Recognizing the cyclical nature of the oil and gas industry, we continue to closely monitor commodity prices and industry trends for signs of deteriorating 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 2014, subject to the Board’s quarterly review and approval.

Fourth Quarter Acquisitions

In October we completed two transactions involving the acquisition of royalty interests in east central Alberta for a total consideration of $6.1 million, including adjustments. These transactions will result in additions to production totaling 59 boe/d weighted 67% oil and NGL’s and 33% gas.

Availability on SEDAR

Freehold’s 2013 third quarter interim unaudited 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.

Forward-looking Statements

This news release offers our assessment of Freehold’s future plans and operations as at November 14, 2013, 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;
• foreign exchange rates;
• industry drilling, development and licensing activity on our royalty lands, our exposure in emerging resource plays, and the potential impact of horizontal drilling on production and reserves;
• development of working interest properties;
• participation in the DRIP and our use of cash preserved through the DRIP;
• estimated capital budget and expenditures and the timing thereof;
• estimated operating expenses;
• long-term debt at year end;
• average production and contribution from royalty lands;
• key operating assumptions;
• amounts and rates of income taxes and timing of payment thereof; and
• maintaining our monthly dividend rate through 2014 and our dividend policy.

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.

With respect to forward-looking statements contained in this news release, we have made assumptions regarding, among other things, future oil and gas prices, future capital expenditure levels, future production levels, future exchange rates, future tax rates, future participation rates in the DRIP and use of cash retained through the DRIP, 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 natural 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, 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. 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 IFRS 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.

Additional GAAP Measures

This news release contains the term “funds from operations”, which does not have a standardized meaning prescribed by GAAP and therefore may not be comparable with the calculations of similar measures for other entities. Funds from operations, as presented, is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to net income or other measures of financial performance calculated in accordance with GAAP. We consider funds from operations to be a key measure of operating performance as it demonstrates Freehold’s ability to generate the necessary funds to fund capital expenditures, sustain dividends, and repay debt. We believe that such a measure provides a useful assessment of Freehold’s operations on a continuing basis by eliminating certain non-cash charges. It is also used by research analysts to value and compare oil and gas companies, and it is frequently included in their published research when providing investment recommendations. Funds from operations per share is calculated based on the weighted average number of shares outstanding consistent with the calculation of net income per share.

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 netback is a useful supplemental measure for management and investors to analyze operating performance. We use this term to facilitate the understanding and comparability of our results of operations. However, this term does not have any standardized meaning prescribed by GAAP and therefore may not be comparable with the calculations of similar measures for other entities.

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. In addition, we refer to various per boe figures also considered non-GAAP measures, 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 and natural gas production during the period, with natural gas converted to equivalent barrels of oil as described above.