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Press release from Marketwire

Freehold Royalties Ltd. Announces 2012 First Quarter Results

Wednesday, May 09, 2012

Freehold Royalties Ltd. Announces 2012 First Quarter Results17:01 EDT Wednesday, May 09, 2012CALGARY, ALBERTA--(Marketwire - May 9, 2012) - Freehold Royalties Ltd. (Freehold) (TSX:FRU) today announced first quarter results for the period ended March 31, 2012.RESULTS AT A GLANCEThree Months EndedMarch 31FINANCIAL ($000s, except as noted)20122011ChangeGross revenue44,36636,23222%Net income (1)13,06011,21916%Per share, basic and diluted ($) (1)0.210.1911%Cash flow from operating activities36,33524,09651%Per share ($)0.580.4141%Funds from operations (2)25,61327,322-6%Per share ($) (2)0.410.46-11%Capital expenditures13,2454,665184%Property and royalty acquisitions (net)49,919321-Dividends declared26,76624,9507%Per share ($) (3)0.420.420%Proceeds from the DRIP (4)6,7896,6951%Long-term debt, period end18,00061,000-70%Shareholders' equity, period end (1)335,743275,58222%Shares outstanding, period end (000s)64,99359,5369%Average shares outstanding (000s) (5)62,57159,3435%OPERATINGAverage daily production (boe/d) (6)8,7337,49017%Average price realizations ($/boe) (6)54.8052.514%Operating netback ($/boe) (2) (6)49.4848.961%(1) Net income, net income per share, and shareholders' equity for the three months ended March 31, 2011 have been restated for revisions made to deferred tax.(2) See Non-GAAP Financial Measures.(3) Based on the number of shares issued and outstanding at each record date.(4) Dividends paid in shares pursuant to the dividend reinvestment plan (DRIP). See Liquidity and Capital Resources - Dividends Paid.(5) Weighted average number of shares outstanding during the period, basic. (6) See Conversion of Natural Gas to Barrels of Oil Equivalent (boe). May Dividend AnnouncementThe Board of Directors has declared the May dividend of $0.14 per share, which will be paid on June 15, 2012 to shareholders of record on May 31, 2012. This dividend is designated as an eligible dividend for Canadian income tax purposes. Including the June 15 payment, our 12-month trailing cash dividends total $1.68 per share. 2012 First Quarter HighlightsGross revenue increased 22%, mainly due to increased production and higher oil prices. Average price realizations were $54.80 per boe, up 4%, and average production was 8,733 boe per day, up 17% from the first quarter of 2011. Net income rose 16%. Non-cash charges included in net income amounted to $16.5 million (Q1 2011 - $18.5 million). Funds from operations declined 6% and on a per share basis declined 11% due to the impact of current income tax. Dividends for the first quarter of 2012 totalled $0.42 per share, unchanged from last year. Average participation in our DRIP was approximately 26% in the first quarter (Q1 2011 - 27%.) Net capital expenditures (working interests) totalled $13.2 million, of which 80% was spent in southeast Saskatchewan. Oil and natural gas liquids (NGL) production rose 13% in the first quarter, and natural gas production rose 23%. While natural gas production accounted for 37% of production in the first quarter, it comprised only 8% of revenue. In January, we acquired royalty interests in over 250,000 gross acres of land for $49.5 million. In February, we closed an equity offering, issuing 3.5 million shares at $20.50 per share. Net proceeds of $67.6 million were used to repay the bank indebtedness associated with the royalty acquisitions completed in September 2011 and January 2012. Royalty Interest DrillingOur royalty lands saw increased oil drilling activity in the first quarter. On an equivalent net basis, royalty drilling rose 56% compared with the first quarter last year. About two-thirds of the wells were oil wells, versus half in the first quarter last year. Oil drilling was up 32%, while natural gas drilling declined 33%. The horizontal drilling trend also continued, as over two-thirds of these wells were horizontal compared to about half last year. As at March 31, 2012, there were 48 (2.9 equivalent net) licensed drilling locations on our royalty lands, compared with 82 (3.8 equivalent net) at the same time last year, and 58 (2.0 equivalent net) at March 31, 2010. Working Interest DrillingOn our working interest properties, we participated in the drilling of 12 (5.9 net) wells with a 100% success rate. In Saskatchewan, we drilled nine (4.6 net) horizontal wells, of which five (3.2 net) were Bakken light oil wells and four (1.4 net) were Frobisher light oil wells. In Lloydminster, we participated in two (1.0 net) Lloydminster heavy oil wells. In Alberta, we participated in one (0.3 net) Boundary Lake light oil well. Net capital expenditures (working interests) totalled $13.2 million, of which 80% was spent in southeast Saskatchewan, where mild weather through the winter allowed us to accelerate our capital spending after delays last year due to a very wet spring and summer. Results to date from our capital program are meeting our expectations, and have led to production increases.ProductionProduction was 17% higher than the first quarter last year, and 12% higher than the fourth quarter of 2011. Royalty interests comprised 74% of total volumes produced in the first quarter 2012 versus 76% in the first quarter last year. Our production mix for the quarter was approximately 37% natural gas and 63% liquids (25% heavy oil, 34% light and medium oil, and 4% NGL). Over the past two years, the composition of our oil production has become lighter, largely as a result of our exposure to the Bakken and Cardium light oil plays.Royalty production rose 13%, including production additions from the royalty acquisitions in September 2011 and January 2012 and strong fourth quarter drilling activity on our lands. In addition, numerous prior period adjustments boosted production volumes by approximately 550 boe per day. The adjustments related in part to the identification of new interests through our ongoing audit program and were evenly split between oil and natural gas volumes. Drilling successes in southeast Saskatchewan also contributed to the increase in oil and NGL production for both royalty and working interests. A portion of the increase represents flush oil production following initial completion of horizontal wells. Activity in this area (operated and non-operated) ramped up in the fourth quarter of 2011 and the first quarter of 2012, following delays due to wet weather last summer. Natural gas production was 23% higher than the first quarter of last year, and 21% higher than the fourth quarter. The increase related primarily to the royalty acquisition completed in January, and the prior period adjustments discussed above. As well, in the first quarter of last year, we recorded a one-time adjustment relating to the payout of a natural gas well in Alberta that effectively reduced working interest natural gas volumes in 2011 Q1 by approximately 600 Mcf (100 boe) per day.Guidance UpdateOverall, the outlook for crude oil remains more favourable than for natural gas.In the first quarter of 2012, the average benchmark West Texas Intermediate (WTI) crude oil price rose 9%, largely driven by supply outages in Sudan, Syria, and Yemen and fears that planned economic sanctions against Iran could limit its crude oil shipments in the second half of this year. Global economic and political uncertainties, including the economies of the European Union, continue to add to volatility. A transportation bottleneck out of North American inland markets (exacerbated by rising U.S. Bakken oil production and increasing oil sands volumes) has served to dislocate the WTI crude oil benchmark from other light oil benchmarks such as European Brent Crude, creating a significant price discount for WTI. The congestion has also widened the price gap between Canadian (Edmonton Par) light crude oil relative to WTI. This price gap is expected to remain wide through the balance of 2012. However, it is anticipated that rail and pipeline projects will be commissioned within the next few years to link U.S. and Canadian oil production to U.S. Gulf Coast refining centres, where international prices prevail.The Canadian light/heavy oil price differential (Edmonton Par versus Western Canada Select) continues to rise and fall in response to domestic supply and demand factors. Canadian differentials averaged $10.57 per boe in first quarter of 2012 compared with $17.78 per boe in the first quarter of 2011. The benchmark Western Canada Select (WCS) heavy oil stream, with an average API gravity of 20.5 degrees, is considered a rough proxy for our average oil price. Oil prices and differentials are expected to remain volatile in the short term, with both upside and downside risks. The benchmark AECO natural gas price declined 33% in the first quarter of 2012. Natural gas, because it is less readily transported, is subject to supply and demand factors within North America. Supply from liquids-rich natural gas basins continues to increase, while demand remains soft due to a warmer than average winter heating season. In the near term, the outlook for natural gas prices remains grim. Although the low price environment has prompted some natural gas producers to shut in production until prices improve, demand growth is not expected to respond quickly enough to absorb the current storage surplus. Longer term, we believe the supply/demand balance will gradually improve, aided by planned LNG projects that should open access to high-demand Asian markets as early as 2015.As the outlook for crude oil is currently much more favourable than for natural gas, industry drilling activity has shifted toward oil and liquids prospects while natural gas development has been curtailed. This, along with the increasing complexity of horizontal wells and longer associated drilling times resulted in 27% fewer wells being drilled in the first quarter compared to last year: a total of 3,121 wells (73% oil) were drilled industry wide versus 4,276 (51% oil) a year ago. The number of oil wells drilled increased 3%, while the number of natural gas wells declined 62%. With strong production performance in the first quarter, we now expect average production for 2012 to be 500 boe per day higher than our previous estimate. Our revised guidance takes into consideration the success of our development program in southeast Saskatchewan, our planned capital program for the balance of the year, anticipated drilling activity on our leased royalty lands (including an expected reduction in natural gas drilling and potential production shut-ins due to weak prices), and historical production decline rates.As a corporation, our taxable income is based on revenues (which will vary depending on commodity prices, production volumes, etc.), less allowable expenses including claims for both accumulated tax pools and tax pools associated with current year expenditures. The corporate income tax rate applicable to 2012 is approximately 25%. As our partnership has a March 31 year-end, we expect to pay no cash income taxes in 2012. However, we expect to have current income tax expense, payable in the first quarter of 2013, of approximately $24 million. In 2013, we will also begin remitting monthly instalments of income tax payable on anticipated 2013 taxable income. The actual amount of tax will vary depending on the factors noted above; however, we currently estimate cash taxes payable in 2013 in the range of $45 to $50 million. The cash outlay for income taxes in 2013 is an anomaly that we have been preparing for, and have the financial capacity to handle.At the end of the first quarter, available capacity under our credit facilities stood at $192 million, which gives us significant financial flexibility to take advantage of acquisition opportunities. We believe producers may look to sell non-core oil and gas assets, and particularly royalty interests, in order to reduce debt and fund their core exploration and development programs. In addition, cash preserved through our DRIP continues to enhance our capital resources. We have maintained a steady monthly dividend rate of $0.14 ($1.68 annually) per share since January 2010. Based on our current guidance and assuming no change in the current business environment, we expect to maintain the current monthly dividend rate through 2012, subject to the Board's quarterly review. The following table summarizes our key operating assumptions, updated to reflect actual results for the first quarter of 2012 and our current expectations for the remainder of the year.2012 KEY OPERATING ASSUMPTIONSMay 9March 1420122012Average daily productionboe/d8,1007,600Average WTI oil priceUS$/bbl100.00100.00Average exchange rateCdn$/US$1.001.00Edmonton Par crude oilCdn$/bbl90.0099.00Western Canada Select (WCS)Cdn$/bbl75.0081.00WTI/Edmonton Par differential$/bbl-10.00-1.00Edmonton Par/WCS differentialCdn$/bbl-15.00-18.00Average AECO natural gas priceCdn$/Mcf2.002.50Average operating costs$/boe4.804.60Average general and administrative costs (1)$/boe3.003.00Capital expenditures$ millions3030Proceeds from DRIP (2)$ millions2727Long-term debt at year end$ millions1815Cash taxes payable in 2012 (3)$ millions--Current income tax expense (payable in 2013) (3)$ millions2421Weighted average shares outstandingmillions6565(1) Excludes share based and other compensation. (2) Average 25% participation rate, which is subject to change. (3) Corporate tax estimates will vary depending on commodity prices and other factors. Forward-Looking StatementsThis news release offers our assessment of Freehold's future plans and operations as at May 9, 2012, and contains forward-looking statements that we believe allow readers to better understand our business and prospects. 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; completion of pipeline projects and the timing thereof; foreign exchange rates; industry drilling, development activity on our royalty lands, our participation in emerging resource plays, and the potential impact of horizontal drilling on production and reserves; reduction in natural gas drilling and potential production shut-ins due to weak prices; 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; long-term debt at year end; average production and contribution from royalty lands; key operating assumptions; acquisition opportunities; current and deferred income tax and our expected taxability and the timing thereof; and our dividend policy.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, 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 AIF.With respect to forward-looking statements contained in this news release, we have made assumptions regarding, among other things, future oil and natural 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 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 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 shown in table above.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 news release 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.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 MeasuresWithin this MD&A, references are made to terms commonly used as key performance indicators in the oil and natural gas industry. We believe that operating netback, funds from operations, and funds from operations per share 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 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.Funds from operations is a financial term commonly used in the oil and gas industry. It is a key measure of our ability to generate cash, finance operations, and pay monthly dividends. 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 define funds from operations as net income adjusted for non-cash depletion and depreciation, share based and other compensation, deferred tax expense, accretion of asset retirement obligation, and management fee, and further adjusted for expenditures on reclamation. 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 and repay debt. We believe that such a measure provides a better assessment of Freehold's operations on a continuing basis by eliminating certain non-cash charges. From a business perspective, the most directly comparable measure of funds from operations calculated in accordance with GAAP is net income. 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. A reconciliation of funds from operations to net income is provided below.RECONCILIATION OF NET INCOME TO FUNDS FROM OPERATIONSThree Months EndedMarch 31($000s)20122011ChangeNet income13,06011,21916%Adjust for non-cash items:Depletion and depreciation16,81112,27837%Share based and other compensation(3,208)(1,353)137%Deferred income tax(1,855)4,170-144%Accretion of asset retirement obligation89829%Management fee922979-6%Adjust for cash item:Expenditures on reclamation(206)-53289%Funds from operations25,61327,322-6%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.Availability on SEDARFreehold's 2012 First Quarter Report, including audited financial statements and accompanying Management's Discussion and Analysis (MD&A), is being filed today with Canadian securities regulators and will be available at and at FOR FURTHER INFORMATION PLEASE CONTACT: Karen TaylorFreehold Royalties Ltd.Manager, Investor Relations and Corporate Secretary403.221.0891 or 1.888.257.1873403.221.0888 (FAX)