Freehold Royalties Ltd. Announces 2012 Fourth Quarter Results and Year-end Reserves

CALGARY, ALBERTA--(Marketwire - March 7, 2013) - Freehold Royalties Ltd. (Freehold) (FRU.TO) today announced 2012 fourth quarter results and reserves as at December 31, 2012.

Results at a Glance

  Three Months Ended   Twelve Months Ended  
FINANCIAL HIGHLIGHTS December 31   December 31  
($000s, except as noted) 2012 2011   Change   2012 2011 Change  
Gross revenue 45,794 45,304   1 % 168,134 157,910 6 %
Net income 13,431 16,033   -16 % 46,328 55,259 -16 %
  Per share, basic and diluted ($) 0.20 0.26   -23 % 0.71 0.92 -23 %
Cash flow from operating activities 38,183 32,595   17 % 138,132 118,370 17 %
  Per share ($) 0.58 0.54   7 % 2.13 1.97 8 %
Capital expenditures 7,743 10,910   -29 % 36,746 25,649 43 %
Property and royalty acquisitions (net) 243 (195 ) -   60,852 7,467 -  
Dividends paid in cash (1) 21,060 15,262   38 % 81,436 67,204 21 %
Dividends paid in shares (DRIP) (1) 6,672 10,232   -35 % 27,414 33,490 -18 %
  Average DRIP participation rate (%) (2) 24 40   -40 % 25 33 -24 %
Dividends declared (3) 27,787 25,585   9 % 109,568 100,968 9 %
  Per share ($) (4) 0.42 0.42   0 % 1.68 1.68 0 %
Long-term debt, period end 18,000 48,000   -63 % 18,000 48,000 -63 %
Shares outstanding, period end (000s) 66,270 61,141   8 % 66,270 61,141 8 %
Average shares outstanding (000s) (5) 66,091 60,811   9 % 64,880 60,022 8 %
                   
OPERATING HIGHLIGHTS                  
Average daily production (boe/d) (6) (7) 9,510 7,773   22 % 8,850 7,476 18 %
Average realized price ($/boe) (6) 51.55 61.90   -17 % 51.00 56.31 -9 %
Operating netback ($/boe) (6) (8) 44.59 56.56   -21 % 45.09 51.65 -13 %
(1) Excludes dividend declared in December and paid in January.
(2) Participation in Freehold's dividend reinvestment plan (DRIP) ranged between 17% and 41% in 2012 and is subject to change monthly at the participants' discretion.
(3) Includes dividend declared in December and paid in January.
(4) Based on the number of shares issued and outstanding at each record date.
(5) Weighted average number of shares outstanding during the period, basic.
(6) See Conversion of Natural Gas to Barrels of Oil Equivalent (boe).
(7) Our production mix in 2012 was approximately 36% natural gas and 64% liquids (34% light and medium oil, 25% heavy oil, and 5% NGL).
(8) See Non-GAAP Financial Measures.

March Dividend Announcement

The Board of Directors has declared the March dividend of $0.14 per share, which will be paid on April 15, 2013 to shareholders of record on March 31, 2013. Including the April 15 payment, our 12-month trailing cash dividends total $1.68 per share. This dividend is designated as an eligible dividend for Canadian income tax purposes. Over the past 16 years, we have paid out over $1.1 billion to our shareholders.

2012 Fourth Quarter Highlights

Freehold delivered strong operational results in the fourth quarter of 2012. Robust production volumes drove increases in revenue and cash flow from operating activities despite lower average realized prices.

  • Average production for the fourth quarter was 22% higher than last year. Drilling activities, including flush production from newly completed horizontal wells, accounted for about two-thirds of the increase; prior period adjustments (650 boe per day versus 350 boe per day in fourth quarter last year) and acquisitions during 2012 accounted for the remainder.
  • Dividends for the fourth quarter of 2012 totalled $0.42 per share, unchanged from last year.
  • Average DRIP participation was 24% in the fourth quarter of 2012 (Q4 2011 - 40%), allowing us to retain $6.7 million (Q4 2011 - $10.2 million) in dividend payments by issuing shares from treasury.
  • Net income of $13.4 million was 16% lower than last year, mainly as a result of increased depletion and depreciation expense, higher royalty expense, and higher operating expense due to a higher production base. Non-cash charges (excluding current income tax) included in net income amounted to $18.1 million (Q4 2011 - $22.3 million).
  • Net capital expenditures on our working interest properties totalled $7.7 million in the fourth quarter (Q4 2011 - $10.9 million), the majority of which was incurred on horizontal drilling and multi-stage fracture well completions in southeast Saskatchewan.
  • Long-term debt was $18.0 million at December 31, 2012, down $7.0 million from the third quarter as excess funds from operations were applied to debt repayment.

2012 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). Freehold is unique in that the majority of our assets are royalty interests. However, under National Instrument 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 others in our industry. 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 proved plus probable reserves at December 31, 2012 totalled 24.4 MMboe, with reserves assigned to 22,589 wells. Net proved plus probable royalty interest reserves increased 10% year-over-year, and net proved plus probable working interest reserves increased 12%. Approximately 62% of our net reserves are in the proved category, and 93% of our net proved reserves are producing. On a boe basis, net reserves are 60% liquids (30% heavy oil, 24% light and medium oil, 6% natural gas liquids) and 40% natural gas.
  • Net proved plus probable reserve additions totalled 5.3 MMboe (45% liquids). Drilling on our royalty lands added 1.0 MMboe (19%) of net proved plus probable reserves, development activities added 0.8 MMboe (15%), and acquisitions added 3.5 MMboe (66%). Based on this, we replaced approximately 167% of 2012 production.
  • Freehold's finding costs are calculated based on net reserves. In 2012, finding and development costs for net proved plus probable reserves were $21.37 per boe, while acquisition costs were $17.47 per boe and the all-in finding, development and acquisition (FD&A) cost was $18.80 per boe (including changes in future development capital). Based on an operating netback of $45.09 per boe in 2012, these activities resulted in a recycle ratio of 2.4 times the capital invested, and a three-year average recycle ratio of 2.1.
  • Our land holdings as at December 31, 2012 encompassed 3.0 million gross acres, up 9% from last year mainly as a result of acquisitions. Royalty interests comprised 94% of our acreage. Our undeveloped land was independently valued by Seaton-Jordan & Associates Ltd., at $80.2 million.

Royalty Interest Activity

On an equivalent net basis, 85% of the royalty wells drilled on our lands during 2012 were oil wells (2011 - 78%) due to the oil-prone nature of our lands. As well, over 66% of the equivalent net wells drilled on our royalty lands in 2012 were horizontal wells, up from 59% last year.

Our royalty lands give us exposure to several of the attractive resource plays employing horizontal drilling, including Bakken and Mississippian light oil in southeast Saskatchewan, heavy oil in the Lloydminster area, and Cardium light oil in west-central Alberta. Over one quarter of the royalty wells drilled in the fourth quarter of 2012 had a Cardium target. Continued success with horizontal drilling (for both oil and liquids-rich natural gas) is positive and bodes well for improved well productivity.

As at December 31, 2012, there were 99 (5.9 equivalent net) licensed drilling locations on our royalty lands, compared with 106 (5.4 equivalent net) at the same time last year. We view continued well licence activity as a positive indicator of the ongoing and future development potential on our royalty lands.

ROYALTY INTEREST WELLS DRILLED Three Months Ended
 December 31
Twelve Months Ended
 December 31
2012 2011 2012 2011
  Gross   Equiv.
Net (1)
Gross   Equiv.
Net (1)
Gross   Equiv.
Net (1)
Gross   Equiv.
Net (1)
Non-unitized 57   2.6 102   4.9 231   11.6 301   14.4
Unitized (2) 30   0.1 60   0.4 200   1.2 322   1.3
Total 87   2.7 162   5.3 431   12.8 623   15.7
(1) Equivalent net wells are the aggregate of the numbers obtained by multiplying each gross well by our royalty interest percentage.
(2) Unitized wells are in production units wherein we generally have small royalty interests in hundreds of wells.

Working Interest Activity

Our development plans are primarily oil related, and are focused almost entirely on our own mineral title lands, where we have chosen to invest our own capital on attractive, low-risk opportunities.

In the fourth quarter of 2012, capital expenditures amounted to $7.7 million, the majority of which was spent to complete, equip, and tie-in wells drilled in southeast Saskatchewan during the third quarter. We participated in the drilling of seven (1.3 net) wells with a 100% success rate.

  • In Saskatchewan, we participated in the drilling of two (0.3 net) vertical and one (0.1 net) horizontal Frobisher oil wells, as well as two (0.6 net) Bakken horizontal oil wells.
  • In Alberta, we participated in one (0.1 net) horizontal Viking light oil well at Redwater and one (0.2 net) horizontal Cardium oil well at Minnehik Buck Lake.

This drilling activity had little effect on production levels in the fourth quarter but is expected to add to our production base in 2013.

WORKING INTEREST WELLS DRILLED (1) Three Months Ended
December 31
Twelve Months Ended
December 31
2012 2011 2012 2011
  Gross   Net Gross   Net Gross   Net Gross   Net
Oil 7   1.3 9   3.8 36   13.5 29   11.1
Natural gas -   - -   - -   - 3   0.4
Other -   - 1   0.1 1   0.6 2   0.1
Total 7   1.3 10   3.9 37   14.1 34   11.6
                         
(1) Excludes royalty interest portion on properties where Freehold has both a working interest and a royalty interest. The royalty interest portion is included in equivalent net wells in the Royalty Interest Wells Drilled table above.

Operating Expense

Total operating expense of $4.8 million ($5.51 per boe) was 28% higher than the fourth quarter last year (4% higher on a per boe basis). The increase correlates to the increase in working interest production volumes, as we do not incur operating expense on our royalty interest production.

GROSS REVENUE BY PRODUCT Three Months Ended   Twelve Months Ended  
  December 31   December 31  
($000s) 2012 2011   Change   2012 2011   Change  
Royalty Interest                    
  Oil 20,503 25,419   -19 % 87,721 85,231   3 %
  NGL 1,512 2,014   -25 % 6,887 6,495   6 %
  Natural gas 3,831 3,402   13 % 10,501 15,581   -33 %
  Other (1) 556 808   -31 % 2,525 3,206   -21 %
  Total royalty interest revenue 26,402 31,643   -17 % 107,634 110,513   -3 %
Working Interest                    
  Oil 17,801 11,847   50 % 55,577 40,786   36 %
  NGL 476 655   -27 % 1,870 2,100   -11 %
  Natural gas 978 922   6 % 2,640 3,447   -23 %
  Other (1) 137 237   -42 % 413 1,064   -61 %
  Total working interest revenue 19,392 13,661   42 % 60,500 47,397   28 %
Total                    
  Oil 38,304 37,266   3 % 143,298 126,017   14 %
  NGL 1,988 2,669   -26 % 8,757 8,595   2 %
  Natural gas 4,809 4,324   11 % 13,141 19,028   -31 %
  Other (1) 693 1,045   -34 % 2,938 4,270   -31 %
  Total gross revenue 45,794 45,304   1 % 168,134 157,910   6 %
(1) Other includes potash, sulphur, lease rentals, and other revenue for royalty interest, and processing fees, interest, and other revenue for working interest.

Fourth Quarter Production

Average production in the fourth quarter of 2012 was 1,737 boe per day higher than last year. Oil and natural gas liquids (NGL) production rose 22%, and natural gas production rose 26%.

  • Royalty production volumes were 594 boe per day higher than last year, mainly as a result of royalty interests acquired during 2012 (which were 90% natural gas) and prior period adjustments due to the ongoing work of our audit team. Natural gas production was up 30%, while oil and NGL production declined 2%.
  • Working interest production volumes were 1,143 boe per day higher than last year as a result of high activity levels in 2012 and flush production from newly completed wells in southeast Saskatchewan. Oil and NGL production was up 69% and natural gas production was up 12%.
AVERAGE DAILY PRODUCTION Royalty Interest Working Interest Total
Three months ended December 31 2012 2011 2012 2011 2012 2011
  Oil (bbls/d) 3,190 3,262 2,561 1,461 5,751 4,723
  NGL (bbls/d) 267 252 88 106 355 358
  Total oil and NGL (bbls/d) 3,457 3,514 2,649 1,567 6,106 5,081
  Natural gas (Mcf/d) 17,105 13,198 3,315 2,952 20,420 16,150
  Oil equivalent (boe/d) 6,308 5,714 3,202 2,059 9,510 7,773

Commodity Prices

In the fourth quarter of 2012, the benchmark West Texas Intermediate (WTI) crude oil price averaged US$88.18 per barrel, 6% lower than the prior year. Prices deteriorated during the quarter, and WTI also continues to trade at a discount to Brent crude, the global benchmark. Historically, WTI has traded at a slight premium over Brent; however during the last two years, WTI has traded consistently at a discount to Brent as a result of market access constraints.

Crude oil supply in North America is growing, primarily from the Canadian oil sands and tight oil plays in western Canada, North Dakota, Montana, and Texas, and global demand remains strong. However, refinery outages and pipeline bottlenecks in the U.S. Midwest have severely reduced access to the Texas and Louisiana Gulf Coast where there is greater refinery demand.

Growing supplies of light crude oil from the United States and a lack of spare pipeline capacity has blends like Edmonton Par and Western Canadian Select (WCS) being steeply discounted against WTI. The widening differentials have been an ongoing issue for Canadian producers throughout 2012 and are expected to remain a concern in 2013.

Natural gas, because it is less readily transported abroad, is subject to supply and demand factors within North America. Although the low price environment of the past three years has served to curtail dry gas drilling, horizontal well technology in shale gas plays and liquids-rich gas development led to record North American production in 2012.

The average benchmark AECO natural gas price was 14% lower in the fourth quarter of 2012 versus Q4 2011. The pricing outlook is bearish in the near term due to the oversupply situation. Longer-term, we believe demand growth, driven by the phasing out of coal-fired power plants in favour of cleaner-burning natural gas, increasing transportation and industrial use, and developing offshore markets, will support stronger natural gas pricing.

Our average selling prices reflect product quality and transportation differences from benchmark prices. In the fourth quarter of 2012, our average realized oil price was $72.40 (Q4 2011 - $85.78) per barrel and our average realized natural gas price was $2.56 (Q4 2011 - $2.91) per Mcf.

Guidance Update

The following table compares changes in our key operating assumptions during 2012 to our actual results for the year. Compared to our November guidance:

  • Average production for the fourth quarter was 856 boe per day higher than the third quarter of 2012 and annual production came in 3% above guidance, mainly due to prior period adjustments and flush production from successful drilling in Southeast Saskatchewan.
  • Average oil prices were slightly lower than our assumptions, while natural gas prices were slightly higher.
  • General and administrative costs per boe were lower than forecast as a result of higher a production base.
  • Capital expenditures were $1.7 million higher than forecast, as we completed and equipped more oil wells than anticipated in the fourth quarter.

2012 Key Operating Assumptions

        Previous Guidance
Annual Average   2012 Actual Results Nov. 8, 2012 Aug. 9, 2012 May 9, 2012 Mar. 14, 2012
Daily production boe/d 8,850   8,600 8,300 8,100 7,600
WTI oil price US$/bbl 94.20 (1) 95.00 93.00 100.00 100.00
Western Canada Select (WCS) Cdn$/bbl 73.08 (1) 75.00 72.00 75.00 81.00
AECO natural gas price Cdn$/Mcf 2.39 (1) 2.25 2.25 2.00 2.50
Exchange rate Cdn$/US$ 1.00   1.00 1.00 1.00 1.00
Operating costs $/boe 4.82   4.80 4.80 4.80 4.60
General and administrative costs (2) $/boe 2.39   2.65 3.00 3.00 3.00
Capital expenditures $ millions 36.7   35 30 30 30
Dividends paid in shares (DRIP) $ millions 27.4   27 27 27 27
Long-term debt at year end $ millions 18   18 21 18 15
Cash taxes paid in 2012 $ millions 4.7   4.6 4.6 - -
Weighted average shares outstanding millions 64.9   65 65 65 65
(1) As reported by the Canadian Association of Petroleum Producers (CAPP).
(2) Excludes share based and other compensation.

2013 Key Operating Assumptions (1)

      Guidance Updated
Annual Average     March 7, 2013   November 8, 2012
Daily production boe/d   8,500   8,400
WTI oil price US$/bbl   95.00   95.00
Western Canada Select (WCS) Cdn$/bbl   71.00   76.00
AECO natural gas price Cdn$/Mcf   3.10   3.25
Exchange rate Cdn$/US$   1.00   1.00
Operating costs $/boe   5.00   5.00
General and administrative costs (2) $/boe   2.60   2.60
Capital expenditures $ millions   30   33
Dividends paid in shares (DRIP) (3) $ millions   28   28
Long-term debt at year end $ millions   48   48
Cash taxes payable in 2013 for 2012 tax year (4) $ millions   23   25
Cash taxes payable for 2013 tax year (instalments) (4) $ millions   25   25
Weighted average shares outstanding millions   67   67
(1) A sensitivity analysis of the potential impact of key variables on funds from operations per share is provided in our 2012 Annual MD&A.
(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 2012 capital was ahead of guidance, we have revised our 2013 capital budget to $30 million. Our development plans are primarily oil related, focused almost entirely on our mineral title lands, and include approximately 40 gross (13 net) 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) and western Alberta (Cardium oil). Almost half of our total capital for the year will be spent in the first quarter of 2013, with area allocations similar to our annual budget. 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 8,500 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 67% of forecasted 2013 production.

In February 2013, we remitted $23 million for estimated 2012 corporate taxes. We expect to pay approximately $25 million for the 2013 tax year by way of monthly instalments. 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.

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, natural gas accounted for 36% of production volumes in the fourth quarter (Q4 2011 - 35%), but only 11% of gross revenue (Q4 2011 - 10%). 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.

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. In particular, our 2013 forecast for Western Canada Select pricing assumes an improvement in the second half of the year, but it is possible that the North American infrastructure constraints will become a longer-term issue for western Canadian production.

Based on our current guidance and commodity price assumptions, and assuming there are no significant changes 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.

Succession Planning

After more than 16 years with Freehold and 29 years with Rife Resources Ltd. (the Manager of Freehold), Mr. William O. Ingram has announced that he plans to retire as President and CEO in May 2013. Mr. Ingram will step down as a director of Freehold but will continue to serve on the boards of Rife and Canpar Holdings Ltd. As well, Dr. P. Michael Maher, who has been a director of Freehold since 1996, will be retiring from the Board in May. The directors of Freehold thank Dr. Maher and Mr. Ingram for their many years of service to Freehold, and wish them both well in their retirement.

Following the retirement of Mr. Ingram in May, the Board plans to appoint Mr. Thomas J. Mullane as President and CEO, and he will stand for election as a director of Freehold at the annual meeting of shareholders to be held on May 15, 2013. Mr. Mullane joined Freehold in 2012 as Executive Vice-President and Chief Operating Officer, and brings a solid background of industry experience and knowledge at a senior level that will be an asset to Freehold in the years to come.

Land and Reserves

Freehold is unique in that the majority of our assets are royalty interests. However, under National Instrument 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 and finding and development costs to others in our industry. We believe the most appropriate measure of reserves and finding and development costs for Freehold is on a net basis.

As at year-end 2012, our undeveloped land was independently valued at $80.2 million by Seaton-Jordan & Associates Ltd. Our total land holdings encompass approximately three million gross acres, 94% of which are royalties. Of this, our mineral title lands (including royalty assumption lands), which we own in perpetuity, cover more than 630,000 acres; all but approximately 107,000 gross acres of which are currently leased to third parties. In addition, we have gross overriding royalty interests in nearly 2.2 million acres.

These royalty interest lands are significant to Freehold. The majority of these lands are leased to third party operators. As a royalty owner, we have no operational control over the operator's future development activities. As such, the extent of drilling and development activity in future years can be difficult to predict. However, these operators have historically invested significant amounts to generate future reserve additions, and production from which Freehold receives certain royalties. Reserve values do not include potential reserve additions that may occur as a result of future drilling on most of our royalty lands. In addition, based on an internal estimate, we have estimated the net present value of the future royalty revenue from our potash reserves at $20.7 million before tax (discounted at 10%).

Our oil and gas reserves were independently evaluated by Trimble Engineering Associates Ltd. (Trimble) as at December 31, 2012. The evaluation was conducted in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in National Instrument 51-101. Our Reserves Committee met with Trimble to review the findings and procedures, and the reserves report has been accepted by our Board.

Summary oil and gas reserves information is provided below. Complete reserves disclosure as required under National Instrument 51-101 will be included in our Annual Information Form.

Summary of Oil and Gas Reserves
As of December 31, 2012
Forecast Prices and Costs (1) Light and Medium Oil     Heavy Oil     Total Crude Oil  
Gross (2 ) Net (3 )   Gross (2 ) Net (3 )   Gross (2 ) Net (3 )
Reserves Category (Mbbls ) (Mbbls )   (Mbbls ) (Mbbls )   (Mbbls ) (Mbbls )
Proved                            
  Developed producing 1,754   3,490     827   4,150     2,581   7,640  
  Developed non-producing 73   64     -   6     73   70  
  Undeveloped -   -     28   23     28   23  
Total proved 1,826   3,554     856   4,178     2,682   7,733  
Probable 1,346   2,301     916   3,197     2,262   5,498  
Total proved plus probable 3,173   5,855     1,771   7,376     4,944   13,231  
                             
  Natural Gas     Natural Gas Liquids     Oil Equivalent  
  Gross (2 ) Net (3 )   Gross (2 ) Net (3 )   Gross (2 ) Net (3 )
Reserves Category (MMcf ) (MMcf )   (Mbbls ) (Mbbls )   (Mboe ) (Mboe )
Proved                            
  Developed producing 4,024   33,628     146   841     3,398   14,085  
  Developed non-producing 59   794     7   7     90   209  
  Undeveloped -   4,314     -   46     28   788  
Total proved 4,083   38,736     154   893     3,516   15,082  
Probable 3,042   20,212     124   476     2,893   9,343  
Total proved plus probable 7,125   58,949     277   1,369     6,409   24,425  
(1) Numbers may not add due to rounding.
(2) Gross reserves are our share of working interest properties before deduction of royalties payable to others. Gross reserves exclude royalty interests.
(3) Net reserves are defined as our share of working interest properties minus royalties payable to others, plus royalties receivable on our royalty lands.

The reserves data below is presented on a net basis (our share of working interest properties minus royalties payable to others, plus royalties receivable on our royalty lands).

Summary of Net Present Values of Future Net Revenue
As of December 31, 2012
Forecast Prices and Costs ($000s) (1)   Before Income Taxes, Discounted at (% per year)
0%   5%   10%   15%   20%
Proved                    
  Developed producing   730,246   537,722   431,272   364,055   317,704
  Developed non-producing   4,259   2,773   1,986   1,517   1,211
  Undeveloped   23,328   16,185   11,818   8,958   6,987
Total proved   757,833   556,679   445,076   374,529   325,902
Probable   564,863   295,635   193,236   142,680   112,973
Total proved plus probable   1,322,696   852,314   638,312   517,209   438,875
                     
    After Income Taxes, Discounted at (% per year) (2)
Reserves Category   0%   5%   10%   15%   20%
Proved                    
  Developed producing   616,012   453,317   363,687   307,156   268,186
  Developed non-producing   3,194   2,060   1,458   1,099   865
  Undeveloped   17,434   12,070   8,789   6,639   5,158
Total proved   636,639   467,447   373,934   314,894   274,210
Probable   420,690   219,454   142,981   105,240   83,075
Total proved plus probable   1,057,329   686,902   516,915   420,134   357,284
(1) Based on the December 31, 2012 escalated oil and gas price forecasts by an independent qualified reserves evaluator. Future net revenue values do not represent fair market value. Reserve values do not include potential reserve additions that may occur as a result of future drilling on our royalty lands. Columns may not add due to rounding.
(2) The after-tax net present value calculation reflects the tax burden on the properties on a standalone basis, utilizing our tax pools to the maximum depreciation rate as currently permitted. It does not consider the corporate-level tax situation, or tax planning. It does not provide an estimate of the value at the corporate level, which may be significantly different. See our financial statements and accompanying MD&A for additional tax information.
   
Total Future Net Revenue (Undiscounted)
As of December 31, 2012
Forecast Prices and Costs ($000s) (1) Reserves Category  
Proved Reserves   Proved Plus Probable Reserves  
Royalty income 660,266   1,136,234  
Revenue from working interest properties 269,358   506,074  
Royalty expense on working interest properties (40,759 ) (83,190 )
Operating costs (121,380 ) (214,202 )
Development costs (1,441 ) (12,560 )
Well abandonment and reclamation costs (8,212 ) (9,661 )
Future net revenue before income taxes 757,833   1,322,696  
Future income taxes (2) (121,194 ) (265,367 )
Future net revenue after income taxes (2) 636,639   1,057,329  
(1) Future net revenue calculation includes future capital expenditures required to bring booked non-producing and undeveloped reserves on production. Future net revenue values do not represent fair market value. Reserve values do not include potential reserve additions that may occur as a result of future drilling on our royalty lands. Columns may not add due to rounding.
(2) The after-tax net present value calculation reflects the tax burden on the properties on a standalone basis, utilizing our tax pools to the maximum depreciation rate as currently permitted. It does not consider the corporate-level tax situation, or tax planning. It does not provide an estimate of the value at the corporate level, which may be significantly different. See our financial statements and accompanying MD&A for additional tax information.
   
Future Development Costs (Undiscounted) ($000s)
Forecast Prices and Costs (1) Proved Reserves Proved Plus Probable Reserves
2013 773 5,538
2014 519 6,525
2015 29 131
2016 29 117
2017 30 119
Remainder 61 130
Total 1,441 12,560
(1) The source of funding for future development costs includes internally generated cash flow, debt or a combination of both. Disclosed reserves and future net revenue will not be materially affected by the costs of funding the future development expenditures. Columns may not add due to rounding.
 
Reserve Life Index
As of December 31, 2012 (1)
 
  Proved Producing Total Proved Proved Plus Probable
Net reserves (Mboe) 14,085 15,082 24,425
Net production (Mboe) 2,518 2,546 2,878
Reserve life index (years) 5.6 5.9 8.5
(1) Reflects the theoretical production life of a property if the remaining reserves were produced out at current rates. The index is calculated by dividing the reserves in the selected reserve category at a certain date by the estimated production for the first year's production period (calculated by dividing the Trimble forecast of 2013 net production into the remaining net reserves).
 
Reconciliation of Net Reserves (1)
By Principal Product Type
 
...
Forecast Prices and Costs (1) Light and Medium Oil   Heavy Oil  
        Proved Plus           Proved Plus  
  Proved   Probable   Probable   Proved   Probable   Probable  
  (Mbbls ) (Mbbls ) (Mbbls ) (Mbbls ) (Mbbls ) (Mbbls )
December 31, 2011 3,445   1,885   5,330   4,533   2,841   7,373  
  Extensions 569   426   995   324   199   523  
  Improved recovery -   -   -   -   -   -  
  Technical revisions 319   (178 ) 142   167   (74 ) 93  
  Discoveries -   -   -   -   -   -  
  Acquisitions 87   165   253   46   232   278  
  Dispositions -   -   -   -   -   -  
  Economic factors 16   3   19   5   -   5  
  Production (883 ) -   (883 ) (897 ) -   (897 )
December 31, 2012 3,554   2,301   5,855   4,178   3,197   7,376  
                         
  Natural Gas   Natural Gas Liquids  
          Proved Plus           Proved Plus  
  Proved   Probable   Probable   Proved   Probable   Probable  
  (MMcf ) (MMcf ) (MMcf ) (Mbbls ) (Mbbls ) (Mbbls )
December 31, 2011 32,560   17,113   49,673   802   405   1,206  
  Extensions 810   523   1,333   42   27   69  
  Improved recovery -   -   -   -   -   -  
  Technical revisions 771   (1,677 ) (906 ) 42   (31 ) 11  
  Discoveries -   -   -   -   -   -  
  Acquisitions 11,765   4,263   16,028   206   75   281  
  Dispositions -   -   -   -   -   -  
  Economic factors (21 ) (10 ) (31 ) -   -   -  
  Production (7,149 ) -   (7,149 ) (198 ) -   (198 )
December 31, 2012 38,736   20,212   58,949   893   476   1,369  
                         
              Oil Equivalent  
                      Proved Plus  
              Proved   Probable   Probable  
              (Mboe ) (Mboe ) (Mboe )
December 31, 2011             14,206   7,982   22,189  
  Extensions             1,071   738   1,809  
  Improved recovery             -   -   -  
  Technical revisions             657   (562 ) 95  
  Discoveries             -   -   -  
  Acquisitions             2,300   1,183   3,483  
  Dispositions             -   -   -  
  Economic factors             17   1   19  
  Production             (3,169 ) -   (3,169 )
December 31, 2012             15,082