Freehold Royalties Ltd. Announces 2012 Third Quarter Results
Freehold Royalties Ltd. Announces 2012 Third Quarter Results and November Dividend
CALGARY, ALBERTA -- (Marketwire) -- 11/08/12 -- Freehold Royalties Ltd. (Freehold) (TSX:FRU) today announced third quarter results for the period ended September 30, 2012.
RESULTS AT A GLANCE Three Months Ended Nine Months Ended September September 30 30 --------------------------------------------------------- FINANCIAL ($000s, except as noted) 2012 2011 Change 2012 2011 Change ---------------------------------------------------------------------------- Gross revenue 41,811 35,819 17% 122,340 112,606 9% Net income 11,975 11,290 6% 32,897 39,226 -16% Per share, basic and diluted ($) 0.18 0.19 -5% 0.51 0.66 -23% Cash flow from operating activities 36,212 30,255 20% 99,949 85,775 17% Per share ($) 0.55 0.50 10% 1.55 1.44 8% Capital expenditures 9,160 5,537 65% 29,003 14,739 97% Property and royalty acquisitions (net) 10,789 7,297 48% 60,609 7,662 691% Dividends paid in cash 20,542 16,482 25% 60,376 51,942 16% Dividends paid in shares (DRIP) 7,013 8,765 -20% 20,742 23,258 -11% Dividends declared (2) 27,616 25,322 9% 81,781 75,383 8% Per share ($) (3) 0.42 0.42 0% 1.26 1.26 0% Long-term debt, period end 25,000 51,000 -51% 25,000 51,000 -51% Shares outstanding, period end (000s) 65,879 60,492 9% 65,879 60,492 9% Average shares outstanding (000s) (4) 65,677 60,198 9% 64,473 59,756 8% OPERATING ---------------------------------------------------------------------------- Average daily production (boe/d) (5) 8,654 7,195 20% 8,628 7,376 17% Average price realizations ($/boe) (5) 51.71 52.80 -2% 50.80 54.32 -6% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Includes dividend declared in September and paid in October. (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).
November Dividend Announcement
The Board of Directors has declared the November dividend of $0.14 per share, which will be paid on December 17, 2012 to shareholders of record on November 30, 2012. This dividend is designated as an eligible dividend for Canadian income tax purposes. Including the December 17, 2012 payment, the twelve-month trailing cash dividends total $1.68 per share.
2012 Third Quarter Highlights
-- Average production for the third quarter rose 20%, while average price realizations fell 2%, resulting in a 17% increase in gross revenue compared to the third quarter of 2011. Production increases were mainly attributed to drilling activities (70%) and acquisitions (30%). -- Oil and natural gas liquids (NGL) production increased 32% in the third quarter, and natural gas production rose 2%. While natural gas production accounted for 33% of boe production in the third quarter, it comprised only 7% of revenue as a result of weak prices. -- Royalty production rose 13%, mainly due to successful royalty drilling in southeast Saskatchewan and east central Alberta, as well as the addition of over 500 boe per day stemming from various royalty interests acquired since September 2011. Working interest production was 40% higher than the third quarter last year as a result of higher activity levels, flush production from newly completed wells, and prior period adjustments of approximately 190 boe per day. -- Cash flow from operating activities rose 20%, and on a per share basis rose 10%, as a result of the factors outlined above. -- Net income of $12 million was 6% higher than last year, mainly as a result of higher revenue, partly offset by higher depletion and depreciation expense. Non-cash charges (excluding current income tax) included in net income amounted to $14.5 million (2011 - $17.7 million). -- Dividends for the third quarter of 2012 totalled $0.42 per share, unchanged from last year. -- Average participation in our DRIP was 25%. Cash retained through the DRIP ($20.7 million in the first nine months of 2012) continued to help fund our capital program. -- Net capital expenditures on our working interest properties totalled $9.2 million ($29.0 million for the year to date), the majority of which was incurred on horizontal drilling and multi-stage fracture well completions in southeast Saskatchewan. -- On August 31, 2012, we acquired approximately 6,100 net acres of leased mineral title lands in Alberta and Saskatchewan. The lands and 90 boe per day (21% royalty production) were purchased for $10.8 million and funded through our existing credit facilities.
Royalty Interest Drilling
On an equivalent net basis, royalty drilling declined 33% from the third quarter last year, while drilling for the year to date declined 3%. The decline can be attributed to a reduction in natural gas drilling due to the low price environment.
To date in 2012, royalty drilling has focused primarily on recognized oil trends within the Alberta and Williston basins, including the Lloydminster heavy oil area, the Mississippian subcrop play of southeast Saskatchewan, and the Cardium light oil play in west central Alberta. Almost 80% of the equivalent net wells drilled in
the first nine months of 2012 were oil, up from 76% oil in the first nine months of last year. Both vertical and horizontal wells were drilled on our royalty lands, with horizontal drilling accounting for 64% of the activity this year as compared to 58% during the same period last year.
As at September 30, 2012, there were 107 (4.8 equivalent net) licensed drilling locations on our royalty lands. On a net basis, this is similar to last year, when there were 118 (4.9 equivalent net) locations. We view continued well licence activity as a positive indicator of the ongoing and future development potential on our royalty lands.
Acquisition of Mineral Title Lands
On August 31, 2012, we acquired approximately 6,100 net acres of leased mineral title lands in Alberta and Saskatchewan. The lands and 90 boe per day (21% royalty production) were purchased for $10.8 million and funded through our existing credit facilities. The vendor had participated to its title interest in a major portion of the development of the lands. The producing assets have a reserve life of 9.5 years based on estimated proved plus probable reserves of 0.3 MMboe. Along with current production (75% liquids), the lands offer future development potential, with exposure to Pekisko light oil in the Twining area of Alberta, and Bakken and Mannville heavy oil in the Plover Lake area of Saskatchewan. Attractive future development drilling on these mineral title lands will help us maintain our overall working interest and royalty production, similar to our approach on other Freehold mineral title lands.
Working Interest Drilling
In the third quarter of 2012, we invested $9.2 million on working interest properties, bringing our capital for the year to date to $29.0 million. In the quarter, we participated in the drilling of 14 (5.9 net) wells with a 93% success rate. In southeast Saskatchewan, we participated in the drilling of one (0.1 net) vertical and three (1.1 net) horizontal Frobisher oil wells, one (0.5 net) horizontal Tilston oil well, one (0.2 net) horizontal Midale oil well, and one (1.0 net) Bakken horizontal oil well. In Lloydminster, we participated in two (1.0 net) horizontal Cummings heavy oil wells, one (0.2 net) horizontal and four (1.8 net) vertical Sparky heavy oil wells. One (0.5 net) of the wells in Lloydminster encountered mechanical problems after drilling into a very good Cummings sand and will be redrilled in 2013.
Capital investment in the fourth quarter of 2012 is expected to be $6 million. Approximately $3 million will be on drilling in southeast Saskatchewan where we plan to drill five (1.0 net) horizontal oil wells, of which two (0.5 net) will be in the Bakken. The balance of the capital ($3 million) is primarily associated with installing equipment and facilities for the 14 (5.9 net) wells drilled in the third quarter.
Our production mix for the first nine months of 2012 was approximately 36% natural gas and 64% liquids (24% heavy oil, 35% light and medium oil, and 5% 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.
Oil and NGL production was 32% higher than the third quarter last year and 22% higher for the year to date, largely due to drilling and completion activity in southeast Saskatchewan. Natural gas production was up 2% in the third quarter and up 9% for the year to date. The increase related primarily to the royalty acquisition completed in January 2012.
Royalty interests comprised 68% (2011 - 72%) of total volumes produced in the third quarter 2012, and 72% (2011 - 75%) for the year to date. Royalty production rose 13%, mainly due to successful royalty drilling in southeast Saskatchewan and east central Alberta, as well as the addition of over 500 boe per day stemming from various royalty interests acquired since September 2011. We have no operational control over our royalty lands and, as we hold small royalty interests in over 26,000 wells, obtaining timely production data from the well operators is extremely difficult. Thus, we use government reporting databases and past production receipts to estimate revenue accruals. Due to the large number of wells in which we have royalty interests, the nature of royalty interests, the lag in receiving production receipts from the operators, and our audit program, our reported royalty volumes usually include adjustments (both positive and negative) for prior periods.
Working interest production was 40% higher for the quarter and 29% higher for the year to date compared to the same periods last year. For the year to date, the increase primarily reflects the results of our development activities in southeast Saskatchewan and significantly higher activity levels compared to last year. The higher activity level resulted in part from the wet weather access problem in southeast Saskatchewan in 2011 and increased activity by other partners in southeast Saskatchewan where we have participated to our title interest. In the first nine months of this year, we participated in 17 (7.9 net) wells in this area, up from 11 (4.7 net) wells drilled in the same period a year ago. Last year, access was limited through the second and third quarters as a result of wet ground conditions, causing a delay in drilling and completion activities. Production in southeast Saskatchewan accounted for approximately 44% (2011 - 33%) of our working interest volumes for the year to date. The third quarter of 2012 also includes flush production from newly completed wells and prior period adjustments amounting to approximately 190 boe per day.
2012 Guidance Update
With strong production performance to date in 2012, we now expect average oil production to be 300 barrels per day higher than our previous estimate, bringing our total production for 2012 to 8,600 boe per day. Our revised guidance takes into consideration the high rate of success to date and the momentum from the very wet 2011 conditions in southeast Saskatchewan; our capital program for the balance of the year; anticipated drilling activity on our leased royalty lands, and historical rates of production decline. On a boe basis, production volumes for 2012 are expected to be approximately 64% oil and NGL, with 72% of production attributable to royalty interest wells. Our success in southeast Saskatchewan has increased both our working interest and our royalty production.
We are increasing our total capital for 2012 to approximately $35 million, mainly due to the high activity levels of our operating partners in southeast Saskatchewan. Capital investment in the fourth quarter is expected to be $6 million.
Long-term debt at year-end is expected to be $18 million, down from our prior estimate of $21 million, despite our increased capital.
For 2013, the Board has approved a capital budget of $33 million. Our development plans are primarily oil related on our mineral title lands and include approximately 40 gross (13 net risked) wells. Roughly half of our capital will be deployed in southeast Saskatchewan (light oil), with the balance allocated to our expanding mineral title opportunity base in both the Lloydminster area (heavy oil), including our recent mineral title land acquisition, and western Alberta (Cardium oil). Spending may be adjusted as the year progresses, depending on the operating environment and 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 2013 production to average approximately 8,400 boe per day. On a boe basis, production volumes for 2013 are expected to be approximately 64% oil and NGL and 36% natural gas. We continue to maintain our royalty focus with royalty production accounting for 70% of forecasted 2013 production.
In 2013, we expect to pay $25 million for 2012 taxes, in addition to the $2.3 million of instalments already made. Also in 2013, we expect to remit higher monthly instalments for the 2013 tax year, totalling approximately $25 million. The large cash outlay for income taxes in 2013 is an anomaly that we have prepared for and have the financial capacity to handle. We expect our tax bill will normalize in 2014, at approximately 20% of pre-tax cash flow.
2013 KEY OPERATING ASSUMPTIONS Annual Average for 2013 ---------------------------------------------------------------------------- Daily production boe/d 8,400 WTI crude oil US$/bbl 95.00 Western Canada Select (WCS) Cdn$/bbl 76.00 AECO natural gas price Cdn$/Mcf 3.25 Exchange rate Cdn$/US$ 1.00 Operating costs $/boe 5.00 General and administrative costs (1) $/boe 2.60 Capital expenditures $ millions 33 Dividends paid in shares (DRIP) (2) $ millions 28 Long-term debt at year end $ millions 48 Cash taxes payable for 2012 tax year $ millions 25 (3) Cash taxes payable for 2013 tax year $ millions 25 (instalments) (3) Weighted average shares outstanding millions 67 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Excludes share based and other compensation. (2) Assumes 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.
As our results demonstrate, we continue to benefit from activity on our oil-weighted asset base, and from relatively strong, if somewhat volatile, crude oil pricing. Of significance, for the year to date, natural gas (on a boe basis) accounted for 36% of production volumes (2011 - 38%), but it comprised only 7% of revenue (2011 - 13%). Clearly, we would benefit from any improvement in natural gas prices. However, despite a significant decline in revenue from natural gas, we have been able to maintain a steady monthly dividend rate of $0.14 ($1.68 annually) per share since January 2010.
We continue to closely monitor commodity prices and industry trends for signs of deteriorating market conditions. Based on our current guidance and commodity price assumptions, and assuming no change in the current business environment, we expect to maintain the current monthly dividend rate through 2013, subject to the Board's quarterly review and approval.
Recognizing the cyclical nature of the oil and gas industry, we caution that systemic negative changes in the outlook for commodity prices (including light/heavy oil price differentials), foreign exchange rates, or production rates could result in adjustments to the dividend rate. It is also inherently difficult to predict activity levels on our royalty lands since we have no operational control and do not know the future plans of the various operators.
This news release offers our assessment of Freehold's future plans and operations as at November 8, 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; -- foreign exchange rates; -- industry drilling and development activity on our royalty lands; -- 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 retained through the DRIP; -- estimated capital budget and expenditures and the timing thereof; -- long-term debt at year end; -- average production, rate of production declines, 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 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.
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.
Availability on SEDAR
Freehold's 2012 Third Quarter Report, including unaudited financial statements and accompanying Management's Discussion and Analysis (MD&A), is being filed today with Canadian securities regulators and will be available at www.sedar.com and at www.freeholdroyalties.com. Contacts: Freehold Royalties Ltd. Karen Taylor Manager, Investor Relations and Corporate Secretary 403.221.0891 or Toll Free: 1.888.257.1873 403.221.0888 (FAX) email@example.com www.freeholdroyalties.com