Freehold Royalties Ltd. Announces 2015 Fourth Quarter Results and Year-end Reserves, Adjusts Dividend

CALGARY, ALBERTA--(Marketwired - Mar 3, 2016) - Freehold Royalties Ltd. (Freehold) (TSX:FRU) today announced 2015 fourth quarter results and reserves as at December 31, 2015.

Results at a Glance

Dividend Announcement

Reflecting continued weakness in commodity prices, Freehold's Board of Directors has approved an adjustment to its monthly dividend to $0.04 per share from $0.07 per share. The Board of Directors has declared a dividend of Cdn. $0.04 per common share to be paid on April 15, 2016 to shareholders of record on March 31, 2016. Including the April 15 payment, our 12-month trailing cash dividends total $0.91 per share. This dividend is designated as an eligible dividend for Canadian income tax purposes.

The dividend reduction aligns with a lower for longer commodity outlook. Freehold's goal is not to pay dividends with debt, thus maintaining strength within our balance sheet and ensuring the long term success of our business model. Freehold will continue to evaluate dividend levels on a quarterly basis, with the expectation to increase dividend levels as funds from operations improve.

2015 Fourth Quarter Highlights

Freehold delivered strong operational results in the fourth quarter of 2015. Some of the highlights included:

• Production for Q4-2015 averaged 11,815 boe/d, a 20% increase over Q4-2014 and a 5% increase over Q3-2015.
• Royalties accounted for 89% of operating income and 78% of production, reinforcing our royalty focus.
• Royalty production was up 26% compared to Q4-2014 averaging 9,249 boe/d. Growth in volumes was associated with a combination of production acquired through the year, new production from drilling on our royalty lands and a strong quarter from our audit function, including compensatory royalties on our mineral title lands, largely responsible for approximately 500 boe/d of prior period adjustments.
• Working interest production averaged 2,566 boe/d for the quarter, up 2% when compared to the same period last year.
• Funds from operations totalled $25.5 million ($0.26/share) in Q4-2015, down 17% from the same period last year owing to continued weakness in oil and natural gas prices.
• Though average commodity price realizations decreased 36% reduced revenues were partly offset by the increase in production volumes, resulting in a 22% decrease in gross revenue compared to Q4-2014.
• Q4-2015 net loss was $7.4 million (Q4-2014 net income $11.1 million) primarily due to a non-cash impairment charge of $8.0 million in our southeast Saskatchewan working interest area, as a result of the continued drop in expected future commodity prices. Lower revenues and higher depletion and depreciation also contributed to the difference.
• Dividends declared for Q4-2015 totalled $0.21 per share, down from $0.42 per share one year ago due to the reduction in funds from operations resulting from lower commodity prices.
• Average participation in our dividend reinvestment plan (DRIP) was 13% (Q4-2014 - 35%). DRIP proceeds for 2015 totalled $17.2 million.
• Net capital expenditures on our working interest properties totalled $5.6 million over the quarter.
• Basic payout ratio (dividends declared/funds from operations) for 2015 totalled 87% while the adjusted payout ratio (cash dividends plus capital expenditures/funds from operations) for the same period was 95%.
• At December 31, 2015, net debt totalled $146.9 million, down $2.1 million from $149.0 million at September 30, 2015. This implies a net debt to 12-month trailing funds from operations ratio of 1.4 times (excluding the proforma effects of acquisitions).

Guidance Update

The table below summarizes our key operating assumptions for 2016.

• Despite lower spending on our working interest and royalty lands, we have not revised our 2016 production forecast (9,800 boe/d). Volumes are expected to be weighted approximately 62% oil and natural gas liquids (NGLs) and 38% natural gas. We continue to maintain our royalty focus with royalty production accounting for 78% of forecasted 2016 production and 94% of operating income.
• Continuing negative momentum in the commodity environment has resulted in a downward revision to our price assumptions. Through 2016, we are now forecasting WTI and WCS prices to average US$35.00/bbl and $31.00/bbl, respectively (previously US$50.00/bbl and $47.00/bbl). Our AECO natural gas price assumption has also been revised downwards to $2.00/mcf (previously $2.75/mcf).
• The Canadian/U.S. exchange rate has been adjusted downwards to $0.72 (previously $0.76), reflecting the recent declining valuation of the Canadian dollar relative to the United States dollar.
• Operating costs have been reduced to $4.75/boe from $5.00/boe representing an increasing portion of our production coming from royalties, which have no operating costs.
• We have revised our general and administration expense to $2.65/boe from $2.85/boe, as a result of cost reduction initiatives.
• Our capital spending budget has been reduced from $15 million to $7 million reflecting the weaker commodity outlook. A large percentage of our capital expenditures program is non-operated and the exact capital is difficult to predict. We expect to have additional information on the spending of our partners as we move through the year.

2016 Key Operating Assumptions

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 of $0.04/share through 2016, subject to the Board's quarterly review and approval.

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.

Fourth Quarter Production

Production volumes in Q4-2015 averaged 11,815 boe/d, an increase of 20% when compared with levels averaged in the comparative period in 2014.

• Royalty production averaged 9,249 boe/d in Q4-2015, a 26% increase when compared to Q4-2014. Oil and natural gas liquids production was up 46%, largely associated with acquisitions and the strength of our audit function. On the natural gas side, volumes were up 4% from Q4-2014.
• Working interest production volumes averaged 2,566 boe/d in Q4-2015, a 2% increase versus Q4-2014.

Royalty Interest Activity

In total, 377 (18.9 equivalent net) wells were drilled on our royalty lands through 2015 which was a 25% improvement versus 2014 on an equivalent net basis. Through Q4-2015, 85 gross (3.6 net) locations were drilled on our royalty lands; this compares to 138 gross (4.3 net) in Q4-2014.

Our royalty lands give us exposure to some of the most economic resource plays currently being pursued in the Western Canadian Sedimentary Basin. Through 2015, we have seen an increase in activity on our lands largely as a result of acquisitions made over the last two years. Some of the royalty drilling highlights are described below.

In the Viking Dodsland play horizontal drilling was very strong within the established royalty area. In 2015, the operator rig released 109 wells and has 64 gross wells licenced, representing a significant ready to drill inventory. The operator is currently focused on completing 21 wells from the Q4-2015 drill program.

In southeast Saskatchewan/Manitoba we have seen continued interest in our royalty lands situated in the heart of the Bakken and Mississippian subcrop play areas. In Q4-2015, seven gross Bakken horizontal wells were drilled on our royalty lands. In the Mississippian play areas, 10 gross horizontals wells were drilled for Midale and Frobisher targets. Operators achieved exceptional production results from these wells with 30-day average rates from each well exceeding 150 boe/d. Royalty drilling activity continued in Manitoba where several operators have drilled six gross wells targeting Reston and Bakken/Three Forks reservoirs.

In Central Alberta, three Nisku horizontals were drilled on our royalty lands located on the prolific Leduc Woodbend reef complex. The operator in this area is targeting the light oil trapped in Nisku reefs draped over the Leduc reef complex. Horizontal drilling and staged fracture treatments are leading to impressive 3-month average production rates of 160 boe/d per well. With modern drilling and completion technology there is abundant incremental light oil remaining to be recovered from these heritage Devonian reef production areas.

In the Deep Basin, we had five deep horizontal wells drilled on our royalty lands. Montney and Wilrich targets are being pursued by several operators in the overpressured liquids rich areas of the basin. Two of these horizontal tests targeting the Wilrich had first month average production exceeding 14 MMcf/d of gas plus associated liquids, which demonstrates the material nature of these play types.

Working Interest Activity

Freehold's working interest drilling program was relatively limited for Q4-2015. Five wells were drilled in our southeast Saskatchewan operating area for Midale and Bakken horizontal targets. Production results are very encouraging with current average production greater than 150 boe/d per well.

In addition, a number of Freehold operated wells drilled in the third quarter were brought on stream in Q4-2015. Two Mississippian Frobisher horizontals (100% interest) were placed on production in December with each well averaging 45 boe/d. Also our vertical heavy oil well drilled in the Greenstreet area (90% interest) was placed on production in November and is currently averaging approximately 40 boe/d.

Freehold is also encouraged by the strong production performance from its Pembina Cardium horizontal well drilled early in 2015 (42.5% working interest, 15% royalty interest). The well continues to produce strongly averaging greater than 250 boe/d for the quarter. Additional downspace locations offsetting this location are ready to be drilled when prices recover.

2015 Year-end Reserves and Land Highlights

Freehold's reserves data is presented on a net basis (our share of working interest properties minus royalties payable to others, plus royalties receivable on our royalty lands), as under National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (NI 51-101), royalty interests cannot be included under gross reserves. This causes our gross reserves to be lower than our net reserves and makes it difficult for investors to compare our reserves to exploration and development companies. We believe the most appropriate measure of reserves for Freehold is net reserves. Reserve values do not include potential reserve additions that may occur as a result of future drilling on most of our royalty lands.

• Net present value of future net reserves before tax totalled $860 million (NPV 10), up from $786 million in 2014. The increase versus 2014 was associated with acquisitions completed through 2015, offset by the reduction in prices.
• Net proved plus probable reserves at December 31, 2015 totalled 36.1 MMboe, with reserves assigned to 26,948 wells. Net proved plus probable royalty interest reserves increased 26% year-over-year, and net proved plus probable working interest reserves were flat. Approximately 64% of our net reserves are in the proved category, and 73% of our net proved reserves are producing. On a boe basis, net reserves are 58% liquids (18% heavy oil, 34% light and medium oil, 6% natural gas liquids) and 42% natural gas.
• On our royalty lands, net proved plus probable reserve additions totalled 9.5 MMboe (81% liquids). Drilling added 0.9 MMboe of net proved plus probable reserves, and acquisitions added 8.6 MMboe of net proved plus probable reserves. Based on this, we replaced approximately 303% of 2015 production.
• Freehold's finding costs are calculated based on net reserves. In 2015, finding and development costs for net proved plus probable reserves were $12.98 per boe (including changes in future development capital), while acquisition costs were $37.87 per boe and the all-in finding, development and acquisition (FD&A) cost was $34.83 per boe (including changes in future development capital). Based on an operating netback of $28.83 per boe in 2015, these activities resulted in a recycle ratio of 0.8, and a three-year average recycle ratio of 1.4.
• Our land holdings as at December 31, 2015 encompassed approximately 3.7 million gross acres, up 16% from last year mainly as a result of acquisitions completed throughout the year. Royalty interests comprised over 90% of our acreage.
• As at year-end 2015, our undeveloped land was independently valued at $111.7 million by Seaton-Jordan & Associates Ltd.

Our oil and gas reserves were independently evaluated by Trimble Engineering Associates Ltd. (Trimble) as at December 31, 2015. The evaluation was conducted in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101. Our Reserves Committee met with Trimble to review the findings and procedures, and the reserves report has been accepted by our Board of Directors.

Summary of Oil and Gas Reserves

As of December 31, 2015

Forecast Prices and Costs⁽¹⁾

Summary of Net Present Values of Future Net Revenue

As of December 31, 2015

Forecast Prices and Costs (000's)⁽¹⁾⁽²⁾

Total Future Net Revenue (Undiscounted)

As of December 31, 2015

Forecast Prices and Costs (000's)⁽¹⁾

Future Development Costs (Undiscounted) ($000s)⁽¹⁾

Reserve Life Index

As of December 31, 2015⁽¹⁾

Reconciliation of Net Reserves⁽¹⁾

By Principal Product Type

Finding, Development and Acquisition (FD&A) Costs⁽¹⁾

Recycle Statistics, Net Proved Plus Probable Reserves

Land Holdings

As of December 31, 2015

Land Holdings by Province

Quarterly Review

Condensed Consolidated Balance Sheets

Condensed Consolidated Statements of Income (Loss) and Comprehensive Income (Loss)

Condensed Consolidated Statements of Cash Flows

Condensed Consolidated Statements of Changes in Shareholders' Equity

Forward-Looking Statements

This news release offers our assessment of Freehold's future plans and operations as at March 3, 2016, 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;
• drilling activity during 2016 and the impact on our production base;
• industry drilling, development 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;
• average production and contribution from royalty lands;
• key operating assumptions;
• amounts and rates of income taxes and timing of payment thereof;
• maintaining our revised monthly dividend rate through 2016 and our dividend policy.

In addition, statements relating to "reserves" and the future net revenue associated with such reserves are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future.

Such statements are generally identified by the use of words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "should", "plan", "intend", "believe", and similar expressions (including the negatives thereof). 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, continued weakness in the oil and gas industry, reliance on third party royalty payors and operators of our working interest properties, volatility of commodity prices, lack of pipeline capacity; 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 AIF.

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 participation rates in the DRIP and use of cash preserved 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 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. 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 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 income, operating netback, net debt obligations, net debt to funds from operations, basic payout ratio and adjusted payout ratio 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 gross 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. Net debt obligations is long-term debt less working capital (current assets less current liabilities). Net debt to funds from operations is calculated as net debt as a proportion of funds from operations for the previous twelve months. In addition, we refer to various per boe figures, such as revenues and costs, 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.

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.

Oil and Gas Metrics

This news release contains a number of oil and gas metrics, including finding and development costs, finding, development and acquisition costs, recycle ratio and reserves life index, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate Freehold's performance; however, such measures are not reliable indicators of the future performance of Freehold and future performance may not compare to the performance in previous periods.

Availability on SEDAR

Freehold's 2015 audited 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. Our Annual Information Form (including reserves disclosure required under National Instrument NI 51-101) is expected to be filed by on or about March 7, 2016.

Contact

Freehold Royalties Ltd.
Matt Donohue
Manager, Investor Relations
403.221.0833 or tf. 1.888.257.1873
403.221.0888
mdonohue@rife.com
www.freeholdroyalties.com