Freehold Royalties Ltd.

Freehold Royalties Ltd.

August 09, 2012 20:39 ET

Freehold Royalties Ltd. Announces 2012 Second Quarter Results and August Dividend

CALGARY, ALBERTA--(Marketwire - Aug. 9, 2012) - Freehold Royalties Ltd. (Freehold) (TSX:FRU) today announced second quarter results for the period ended June 30, 2012.


Three Months Ended June 30 Six Months Ended June 30
Financial ($000s, except as noted) 2012 2011 Change 2012 2011 Change
Gross revenue 36,163 40,555 -11 % 80,529 76,787 5 %
Net income 7,862 16,717 -53 % 20,922 27,936 -25 %
Per share, basic and diluted ($) 0.12 0.28 -57 % 0.33 0.47 -30 %
Cash flow from operating activities 27,402 31,424 -13 % 63,737 55,520 15 %
Per share ($) 0.42 0.53 -21 % 1.00 0.93 8 %
Dividends paid in cash 20,397 17,254 18 % 39,834 35,460 12 %
Dividends paid in shares (DRIP) 6,940 7,798 -11 % 13,729 14,493 -5 %
Dividends declared (1) 27,399 25,111 9 % 54,165 50,061 8 %
Per share ($) (2) 0.42 0.42 0 % 0.84 0.84 0 %
Capital expenditures 6,598 4,537 45 % 19,843 9,202 116 %
Property and royalty acquisitions (net) (99 ) 44 -325 % 49,820 365 -
Long-term debt, period end 23,000 54,000 -57 % 23,000 54,000 -57 %
Shareholders' equity, period end 324,100 275,874 17 % 324,100 275,874 17 %
Shares outstanding, period end (000s) 65,440 59,954 9 % 65,440 59,954 9 %
Average shares outstanding (000s) (3) 65,159 59,716 9 % 63,865 59,531 7 %
Average daily production (boe/d) (4) 8,501 7,445 14 % 8,617 7,467 15 %
Average price realizations ($/boe) (4) 45.74 57.61 -21 % 50.33 55.07 -9 %

(1) Includes dividend declared in June and payable in July.

(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).

2012 Second Quarter Highlights

  • Average production for the second quarter rose 14%, while average price realizations fell 21%, resulting in an 11% decline in gross revenue compared to the second quarter of 2011.
  • Oil and natural gas liquids (NGL) production increased 21% in the second quarter, and natural gas production rose 4%. While natural gas production accounted for 37% of boe production in the second quarter, it comprised only 6% of revenue as a result of weak prices.
  • Cash flow from operating activities declined 13%, and on a per share basis declined 21%, as a result of the factors outlined above, cash taxes paid, and changes in non-cash working capital.
  • Net income of $7.9 million was 53% lower than last year, mainly as a result of lower revenue, higher depletion and depreciation expense, and higher taxes. Non-cash charges (excluding current income tax) included in net income amounted to $12.8 million (Q2 2011 - $17.2 million).
  • Dividends for the second quarter of 2012 totalled $0.42 per share, unchanged from last year.
  • Average participation in our DRIP was 25% in the second quarter (26% for the year to date). Cash conserved through the DRIP ($13.7 million in the first half of 2012) continued to enhance our capital resources.
  • Net capital expenditures on our working interest properties totalled $6.6 million ($19.8 million for the year to date), the majority of which was incurred on horizontal drilling and multi-stage fracture well completions in southeast Saskatchewan.

August Dividend Announcement

The Board of Directors has declared the August dividend of $0.14 per share, which will be paid on September 17, 2012 to shareholders of record on August 31, 2012. This dividend is designated as an eligible dividend for Canadian income tax purposes. Including the September 17, 2012 payment, the twelve-month trailing cash dividends total $1.68 per share.

Royalty Interest Drilling

On an equivalent net basis, royalty drilling declined 36% compared with the second quarter last year although drilling for the year to date was up 21%.

To date in 2012, royalty drilling has primarily focused on recognized oil trends within the Alberta and Williston basins. Over 80% of the equivalent net wells drilled in the first six months of 2012 were oil, up from 66% oil in the first half of last year. Operators drilled 85 gross oil wells targeting the light oil plays in the Cardium of the Pembina area as well as the Mississippian and Bakken of southeast Saskatchewan. The Lower Mannville heavy oil area in Lloydminster was also active. Both vertical and horizontal wells were drilled on our royalty lands, with horizontal drilling accounting for 57% of the activity this year as compared to 48% in the first half of last year.

As at June 30, 2012, there were 118 (5.5 equivalent net) licensed drilling locations on our royalty lands, up on a net basis compared with 135 (5.1 equivalent net) locations at the mid-point of last year. We view continued well licence activity as a positive indicator of the ongoing and future development potential on our royalty lands.

Working Interest Drilling

In the second quarter of 2012, we invested $4.6 million on drilling and completions and $1.7 million on new well facilities and $0.3 million on land and seismic. Capital expenditures for the first six months of the year totalled $19.9 million, roughly 80% of which was spent in southeast Saskatchewan. We have no capital requirements with respect to our royalty properties.

During the quarter, we participated in the drilling of four (1.0 net) wells with a 100% success rate. In southeast Saskatchewan, we participated in the drilling of one (0.3 net) horizontal Frobisher oil well. In Lloydminster, we participated in one (0.5 net) vertical Sparky heavy oil well. In Alberta, we participated in two (0.2 net) horizontal Viking oil wells at Redwater. Mild weather has allowed us to accelerate our 2012 capital program and, with nearly two-thirds of our $30 million capital budget spent in the first half of this year, results to date are meeting our expectations.


Royalty interests comprised 76% of total volumes produced in the second quarter 2012 versus 77% in the second quarter last year. Royalty production rose 13%, including production additions from the royalty acquisitions in September 2011 and January 2012. In addition, numerous prior period adjustments boosted royalty production volumes by approximately 500 boe per day. The adjustments related in part to the identification of new interests through our ongoing audit program and were approximately 80% oil.

Oil and NGL production was 21% higher than the second quarter last year and 17% higher for the year to date, largely due to drilling success in southeast Saskatchewan. Natural gas production was up 4% in the second quarter and up 13% for the year to date. The increase related primarily to the royalty acquisition completed in January 2012, and the prior period adjustments discussed above.

Our production mix for the first half of 2012 was approximately 37% natural gas and 63% liquids (25% heavy oil, 33% 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.

Guidance Update

The average West Texas Intermediate (WTI) crude oil price was US$93.49 per barrel in the second quarter of 2012, down 9% from the second quarter last year but virtually unchanged compared to the average for the first half of last year. The transportation bottleneck out of North American inland markets (exacerbated by rising U.S. Bakken oil production and increasing oil sands volumes) continues to create a significant price discount for WTI at Cushing, Oklahoma, relative to other light oil benchmarks such as European Brent Crude. The congestion also continued to widen the price gap between Canadian (Edmonton Par) light crude oil relative to WTI, which rose to average over $10 per barrel in the first half of this year. This price gap is expected to remain wide through the balance of 2012.

To alleviate the current transportation bottleneck, several new pipeline projects have been proposed that will link U.S. and Canadian oil production to U.S. Gulf Coast refining centres, where international prices prevail. With the delay in pipeline approvals and construction, transportation of oil and bitumen by rail has increased as some producers are accessing existing rail infrastructure to ship oil to the U.S. Rail has the potential to become a viable long-term transportation option while providing access to new markets, and new rail projects are also underway.

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; however to date in 2012, the average price differential has improved by 40% compared with last year reflecting robust demand for heavier grades of crude. 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 average AECO natural gas price was 51% lower than the second quarter of last year and 41% lower than the first half of last year. Despite lower natural gas drilling, supply continues to outstrip demand in North American markets following a mild winter, with storage levels remaining above the five-year average. In the near term, the outlook for natural gas remains challenging, although a continuation of hot summer weather could result in modest price improvements. Longer term, we believe the supply/demand balance will gradually improve, aided by the gradual phasing out of coal-fired power generation in favour of natural gas and several planned LNG (liquefied natural gas) export projects that should open access to high-demand Asian markets as early as 2015.

With natural gas trading at the lowest prices seen in years, a number of producers have temporarily shut-in high-cost production and some have pared back their 2012 capital spending budgets.

Industry drilling continues to favour higher value oil and liquids plays, while dry gas activity remains muted. Although spring break-up was mild compared to last year (when forest fires in northern Alberta and flooding in southeastern Saskatchewan created a challenging operating environment), industry drilling was down 19%, with 2,684 wells drilled in western Canada versus 3,323 wells during the second quarter last year. Of significance, only 346 wells were natural gas, a significant drop from the 980 natural gas wells drilled during the same period last year.

In late May, the Canadian Association of Oilwell Drilling Contractors (CAODC) released an updated forecast of western Canada drilling activity for 2012. The average number of days per well is expected to be 12 days (previously 11.5 days) with an estimated 11,834 wells drilled (previously 12,672 wells) versus 16,081 wells drilled in 2011. The CAODC forecast also highlights the trend towards deeper and more complex horizontal wells with longer associated drilling times.

To date, our partnership structure has kept tax payments low. We have made small tax payments in 2012 with expectations of larger payments in 2013. Tax payments in the second quarter of 2012 included $2.3 million for charges resulting from our conversion from a trust to a corporation that would otherwise have been the responsibility of our unitholders. In addition, instalments made throughout 2012 are expected to total another $2.3 million. In 2013, we expect to pay $23 million for 2012 taxes in addition to the 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.

The table below summarizes our key operating assumptions, updated to reflect actual results for the first half of 2012 and our current expectations for the remainder of the year. The changes reflect the following factors:

  • Commodity prices have been adjusted to reflect actual prices for the first six months of 2012 (as reported by CAPP) and our expectations for the second half of the year.
  • With strong production performance to date in 2012, we now expect average oil production to be 200 barrels of oil per day higher than our previous estimate. Our revised guidance takes into consideration the success to date of our development program in southeast Saskatchewan, our 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 production shut-ins due to weak prices), and historical rates of production decline. On a boe basis, production volumes for 2012 are expected to be approximately 62% oil and NGL, with 75% of production attributable to royalty interest wells.
  • We now expect to incur cash taxes of $4.6 million in 2012.
  • With lower oil price assumptions and higher taxes, partly offset by higher production, long-term debt at year-end is expected to be $21 million.


Guidance Dated
Annual Average August 9 May 9 March 14
Daily production boe/d 8,300 8,100 7,600
WTI crude oil (1) US$/bbl 93.00 100.00 100.00
Western Canada Select (WCS) (1) Cdn$/bbl 72.00 75.00 81.00
AECO natural gas price (1) Cdn$/Mcf 2.25 2.00 2.50
Exchange rate Cdn$/US$ 1.00 1.00 1.00
Operating costs $/boe 4.80 4.80 4.60
General and administrative costs (2) $/boe 3.00 3.00 3.00
Capital expenditures $ millions 30 30 30
Dividends paid in shares (DRIP) (3) $ millions 27 27 27
Long-term debt at year end $ millions 21 18 15
Cash taxes payable in 2012 (4) $ millions 4.6 - -
Weighted average shares outstanding millions 65 65 65

(1) Actual prices reported by the Canadian Association of Petroleum Producers (CAPP) and Freehold's estimate for the remainder of the year.

(2) Excludes share based and other compensation.

(3) Assumes 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.

As our results for the first half of 2012 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, natural gas (on a boe basis) accounted for 37% of production volumes (H1 2011 - 38%), but it comprised only 7% of revenue (H1 2011 - 13%). 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. Clearly, we would benefit from any improvement in natural gas prices. Oil prices remain volatile and we continue to closely monitor developments 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 2012, subject to the Board's quarterly review. 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.

Forward-Looking Statements

This news release offers our assessment of Freehold's future plans and operations as at August 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.

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 Second 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

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