MDU Resources Reports 2011 Results, Initiates Guidance for 2012
· | Consolidated full year and 4th quarter earnings per share: |
2011 Earnings Per Share | ||||||||
Full Year | 4th Quarter | |||||||
Continuing operations | $ | 1.19 | $ | 0.39 | ||||
Discontinued operations* | (0.07 | ) | (0.07 | ) | ||||
Consolidated earnings per share | $ | 1.12 | $ | 0.32 | ||||
*Refer to "Other" section on page 16. |
· | Oil production increases 12% in 4th quarter over a year ago, driven by record Bakken production. |
· | Cash flows from operations increased 14% to $627 million from prior year. |
· | Solid balance sheet with equity of 66% of total capital. |
· | Approx. $700 million in planned capital investments for 2012. |
· | Projecting 20% to 30% increase in oil production for 2012. |
· | Initial earnings guidance for 2012 of $1.00 to $1.25 per common share. |
BISMARCK, N.D. – Feb. 1, 2012 – MDU Resources Group, Inc. (NYSE:MDU) today reported 2011 consolidated earnings of $212.3 million or $1.12 per share. This compares to 2010 earnings of $240.0 million or $1.27 per share. Earnings from continuing operations were $225.2 million or $1.19 per share, compared to earnings from continuing operations in 2010 of $243.3 million or $1.29 per share.
Consolidated earnings for the fourth quarter of 2011 were $60.8 million, or 32 cents per share compared to $88.8 million or 47 cents per share in 2010. Fourth quarter 2011 earnings from continuing operations were $73.9 million or 39 cents per share. This compares to earnings from continuing operations in the final quarter of 2010 of $92.1 million or 49 cents per share which includes the gain on the sale of the Brazilian transmission assets of $13.8 million after tax.
“Our businesses finished the year strong and we made substantial progress in preparing the company for future growth,” said Terry D. Hildestad, president and chief executive officer of MDU Resources. “We successfully completed the first stage of a multi-year capital investment effort that we believe will increase our competitiveness and profitability. We also increased our dividend for the 21st consecutive year.”
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The company invested approximately $480 million in capital expenditures during 2011, and expects to increase spending by 45 percent to approximately $700 million this year. Over the next five years total capital expenditures are estimated to be about $3.7 billion. Based on this level of capital expenditures relative to current forecast assumptions, the company does not expect to require equity as a funding source. The company expects cash generated from operations to be the primary source of funds and debt issuance a secondary source largely to maintain targeted capital ratios.
Hildestad said the increased funding enabled the company’s exploration and production business to accelerate development of existing leaseholds, particularly in the prolific Bakken oil play in North Dakota. The company’s record-level Bakken production helped drive oil production higher by 12 percent for the fourth quarter and 7 percent for the year. “We continue to invest in this business as we focus on a more balanced commodity mix of oil and natural gas. In 2011 oil grew to represent 32 percent of our production, up from 16 percent five years ago. For 2012, we are forecasting this trend to continue with our current projection of 20 percent to 30 percent increase in oil production from 2011 levels.”
The utility business reported an increase in year-over-year earnings, helped by an increase in electric and natural gas deliveries to retail customers. The increased natural gas volumes were partially the result of colder weather, particularly in the Pacific Northwest. In addition, low natural gas prices are providing an incentive for fuel-switching in agricultural, commercial and industrial applications. Hildestad added, “The utility had a strong year in 2011. Looking forward, it is exciting to have additional significant long-term organic growth opportunities in this business. We are forecasting an increase in our rate base of 6 percent compounded annually through 2016 for projects that will benefit our customers, as well as our shareholders.”
The pipeline and energy services segment experienced a significant decline in throughput, primarily because of lower storage levels which have declined from record levels in 2010 because of considerably narrowed pricing spreads. The segment is seeing higher natural gas transportation levels in the Bakken region as associated natural gas production in the area is expected to continue to increase.
The company announced at year end that it has combined its construction businesses under the leadership of John Harp, who previously led the construction services segment. Earnings at these two segments totaled $48.0 million in 2011 compared to $47.6 million in 2010. Required investment levels in public infrastructure and the timing of the recovery in the private sector are both positive factors for the long-term earnings growth potential of these businesses. Although the company is seeing stabilization in certain markets, it is uncertain how these factors will impact 2012 at this time.
“Our success this past year and our solid financial condition, including a strong balance sheet and good cash flow, provide a good foundation for future growth,” Hildestad said.
“For 2012, we are excited about our planned increase in capital expenditures focused on growth in our oil drilling program and our regulated utility. In addition, we continue to pursue acquisition opportunities in each of our lines of business and have recently added to our leasehold position in the Bakken area where we now hold approximately 95,000 net acres. Our initial earnings guidance is in the range of $1.00 to $1.25 per common share for the year. We have factored in lower natural gas prices, the uncertainties related to construction spending levels, as well as lower gathering volumes and continued narrow pricing spreads at our pipeline business.”
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The company will host a webcast at 11 a.m. EST Feb. 2 to discuss earnings results and initial guidance for 2012. The event can be accessed at www.mdu.com. A webcast replay and audio replay will be available. The dial-in number for audio replay is (855) 859-2056 or (404) 537-3406 for international callers, conference ID 40840208.
MDU Resources Group, Inc., a member of the S&P MidCap 400 index, provides value-added natural resource products and related services that are essential to energy and transportation infrastructure, including regulated utilities and pipelines, exploration and production, and construction materials and services companies. For more information about MDU Resources, see the company's Web site at www.mdu.com or contact the Investor Relations Department at investor@mduresources.com.
Contacts
Financial:
Phyllis A. Rittenbach, director - investor relations, (701) 530-1057
Media:
Rick Matteson, director of communications and public affairs, (701) 530-1700
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Performance Summary and Future Outlook
The following information highlights the key growth strategies, projections and certain assumptions for the company and its subsidiaries and other matters for each of the company’s businesses. Many of these highlighted points are “forward-looking statements.” There is no assurance that the company’s projections, including estimates for growth and changes in earnings, will in fact be achieved. Please refer to assumptions contained in this section, as well as the various important factors listed at the end of this document under the heading “Risk Factors and Cautionary Statements that May Affect Future Results.” Changes in such assumptions and factors could cause actual future results to differ materially from growth and earnings projections.
Business Line | 2011 Earnings (In Millions) | 2010 Earnings (In Millions) | ||||||
Exploration and Production | $ | 80.3 | $ | 85.6 | ||||
Regulated | ||||||||
Electric and natural gas utilities | 67.6 | 65.9 | ||||||
Pipeline and energy services | 23.1 | 23.2 | ** | |||||
Construction | ||||||||
Construction materials and contracting | 26.4 | 29.6 | ||||||
Construction services | 21.6 | 18.0 | ||||||
Other | 6.2 | 21.0 | *** | |||||
Earnings before discontinued operations | 225.2 | 243.3 | ||||||
Loss from discontinued operations, net of tax | (12.9 | )* | (3.3 | ) | ||||
Earnings on common stock | $ | 212.3 | $ | 240.0 | ||||
*Reflects an arbitration charge of $13.0 million after tax related to a guarantee of a construction contract. **Reflects a natural gas gathering arbitration charge of $16.5 million after tax. ***Reflects a gain on the sale of the Brazilian transmission lines of $13.8 million after tax. |
On a consolidated basis, the following information highlights the key growth strategies, projections and certain assumptions for the company:
· | Earnings per common share for 2012, diluted, are projected in the range of $1.00 to $1.25. The company expects the approximate percentage of 2012 earnings per common share by quarter to be: |
- | First quarter - 15 percent |
- | Second quarter - 15 percent |
- | Third quarter - 40 percent |
- | Fourth quarter - 30 percent |
· | Although near term market conditions are uncertain, the company’s long-term compound annual growth goals on earnings per share from operations are in the range of 7 percent to 10 percent. |
· | The company continually seeks opportunities to expand through strategic acquisitions and organic growth opportunities. |
· | Capital expenditures for 2011 and estimated capital expenditures for 2012 through 2016 are noted in the following table: |
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Business Line | Capital Expenditures 2011 Actual (In Millions) | Capital Expenditures 2012 Estimated* (In Millions) | Capital Expenditures 2012 – 2016 Total Estimated* (In Millions) | |||||||||
Exploration and Production | $ | 273 | $ | 400 | $ | 2,155 | ||||||
Regulated | ||||||||||||
Electric | 52 | 109 | 527 | |||||||||
Natural gas distribution | 71 | 108 | 388 | |||||||||
Pipeline and energy services | 45 | 32 | 333 | |||||||||
Construction | ||||||||||||
Construction materials and contracting | 52 | 45 | 235 | |||||||||
Construction services | 10 | 12 | 63 | |||||||||
Other | 19 | 1 | 5 | |||||||||
Net proceeds and other | (41 | ) | (9 | ) | (11 | ) | ||||||
Total Capital Expenditures | $ | 481 | $ | 698 | $ | 3,695 |
* Capital expenditures relative to potential acquisitions of businesses would be incremental to these estimates.
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Exploration and Production
Three Months Ended | Twelve Months Ended | |||||||||||||||
December 31, | December 31, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(Dollars in millions, where applicable) | ||||||||||||||||
Operating revenues: | ||||||||||||||||
Natural gas | $ | 40.0 | $ | 51.9 | $ | 175.6 | $ | 219.6 | ||||||||
Oil | 76.1 | 57.0 | 278.0 | 214.8 | ||||||||||||
116.1 | 108.9 | 453.6 | 434.4 | |||||||||||||
Operating expenses: | ||||||||||||||||
Operation and maintenance: | ||||||||||||||||
Lease operating costs | 19.8 | 16.9 | 75.6 | 68.5 | ||||||||||||
Gathering and transportation | 6.2 | 5.9 | 24.3 | 23.5 | ||||||||||||
Other | 9.2 | 7.6 | 36.5 | 32.5 | ||||||||||||
Depreciation, depletion and amortization | 36.6 | 34.1 | 142.6 | 130.5 | ||||||||||||
Taxes, other than income: | ||||||||||||||||
Production and property taxes | 10.3 | 8.9 | 40.8 | 35.5 | ||||||||||||
Other | .1 | .1 | --- | .7 | ||||||||||||
82.2 | 73.5 | 319.8 | 291.2 | |||||||||||||
Operating income | 33.9 | 35.4 | 133.8 | 143.2 | ||||||||||||
Earnings | $ | 20.2 | $ | 20.7 | $ | 80.3 | $ | 85.6 | ||||||||
Production: | ||||||||||||||||
Natural gas (MMcf) | 10,931 | 12,653 | 45,598 | 50,391 | ||||||||||||
Oil (MBbls) | 933 | 835 | 3,500 | 3,262 | ||||||||||||
Total production (MMcfe) | 16,525 | 17,665 | 66,596 | 69,963 | ||||||||||||
Average realized prices (including hedges): | ||||||||||||||||
Natural gas (per Mcf) | $ | 3.66 | $ | 4.10 | $ | 3.85 | $ | 4.36 | ||||||||
Oil (per barrel) | $ | 81.62 | $ | 68.30 | $ | 79.43 | $ | 65.85 | ||||||||
Average realized prices (excluding hedges): | ||||||||||||||||
Natural gas (per Mcf) | $ | 2.86 | $ | 3.07 | $ | 3.30 | $ | 3.57 | ||||||||
Oil (per barrel) | $ | 83.96 | $ | 71.09 | $ | 83.30 | $ | 66.71 | ||||||||
Average depreciation, depletion and amortization rate, per equivalent Mcf | $ | 2.12 | $ | 1.84 | $ | 2.04 | $ | 1.77 | ||||||||
Production costs, including taxes, per equivalent Mcf: | ||||||||||||||||
Lease operating costs | $ | 1.20 | $ | .96 | $ | 1.13 | $ | .98 | ||||||||
Gathering and transportation | .38 | .33 | .36 | .34 | ||||||||||||
Production and property taxes | .62 | .50 | .61 | .51 | ||||||||||||
$ | 2.20 | $ | 1.79 | $ | 2.10 | $ | 1.83 | |||||||||
Note: Oil includes crude oil, condensate and natural gas liquids. |
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2011 | 2010 | |||||||||||||||
Natural Gas | Oil | Natural Gas | Oil | |||||||||||||
(MMcf/MBbls) | ||||||||||||||||
Production by region: | ||||||||||||||||
Rocky Mountain | 34,472 | 2,489 | 39,160 | 2,365 | ||||||||||||
Mid-Continent/Gulf States* | 11,126 | 1,011 | 11,231 | 897 | ||||||||||||
Total production | 45,598 | 3,500 | 50,391 | 3,262 | ||||||||||||
* Includes Offshore Gulf of Mexico. |
Earnings at this segment were $80.3 million for 2011, compared to $85.6 million for 2010. This decrease reflects 12 percent lower average realized natural gas prices, as well as decreased natural gas production of 10 percent. The earnings decrease also reflects higher depreciation, depletion and amortization expense, increased lease operating costs, higher production and property taxes, as well as higher general and administrative costs. These decreases were partially offset by 21 percent higher average realized oil prices and increased oil production of 7 percent.
Fourth quarter earnings were $20.2 million, compared to 2010 fourth quarter earnings of $20.7 million. This change reflects decreased natural gas production of 14 percent, lower average realized natural gas prices of 11 percent, increased lease operating costs, higher depreciation, depletion and amortization expense, higher general and administrative costs, as well as higher production and property taxes. These decreases were partially offset by 20 percent higher average realized oil prices, as well as increased oil production of 12 percent.
The following information highlights the key growth strategies, projections and certain assumptions for this segment:
· | The company expects to spend approximately $400 million in capital expenditures in 2012. The company continues its focus on returns by allocating the majority of its capital investment into the production of oil in the current commodity price environment. Its capital program reflects further exploitation of existing properties, acquisition of additional leasehold acreage, and exploratory drilling. The 2012 planned capital expenditure total does not include potential acquisitions of producing properties. |
· | For 2012, the company expects a 20 percent to 30 percent increase in oil production and a 12 percent to 16 percent decrease in natural gas production. The projected decline in natural gas production is primarily the result of the anticipated divestment of certain natural gas properties and the deferral of certain natural gas development activity because of sustained low natural gas prices. |
· | The company has a total of 8 drilling rigs deployed on its acreage in the Bakken, Niobrara, Texas, Paradox, Heath Shale and Big Horn areas, up from 2 rigs in the first quarter of 2011. Dependent upon results during 2012, further growth in rig activity could occur. |
· | Bakken Area |
– | The company owns a total of approximately 95,000 net acres of leaseholds. |
– | Capital expenditures are expected to total approximately $160 million this year; approximately $60 million higher than the capital spent for 2011. |
– | Mountrail County, North Dakota |
§ | The company owns approximately 16,000 net acres of leaseholds targeting the middle Bakken and Three Forks formations. |
§ | The drilling of 17 operated and participation in various non-operated wells is expected for this year with approximately $75 million of capital expenditures. |
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§ | Over 50 future gross well sites have been identified. Estimated gross ultimate recovery per well is 250,000 to 500,000 Bbls. |
– | Stark County, North Dakota |
§ | The company holds approximately 50,000 net exploratory leasehold acres, targeting the Three Forks formation. |
§ | The drilling of 7 operated wells and participation in various non-operated wells is expected for this year with approximately $60 million of capital expenditures. |
§ | Based on 640-acre spacing, approximately 140 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 Bbls. |
– | Richland County, Montana |
§ | The company has increased its acreage to approximately 30,000 net exploratory leasehold acres, targeting the Three Forks formation. |
§ | The first appraisal well is expected to be spud in the first quarter and a total of 5 operated wells are planned for this year with approximately $25 million of capital expenditures. |
§ | Approximately 100 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 Bbls. |
· | Niobrara – southeastern Wyoming |
– | The company holds approximately 65,000 net exploratory leasehold acres. |
– | The drilling of 4 operated wells and participation in various non-operated wells is expected for this year with approximately $25 million of capital expenditures. |
– | Approximately 200 potential gross well sites have been identified based on 640-acre spacing. Estimated gross ultimate recovery rates per well are 200,000 to 300,000 Bbls. |
· | Paradox Basin – Cane Creek Federal Unit, Utah |
– | The company holds approximately 75,000 net exploratory leasehold acres. |
– | The drilling of 4 operated wells is expected this year with capital expenditures of approximately $35 million. |
– | Approximately 70 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well are 250,000 to 500,000 Bbls. |
· | Texas |
– | The company is targeting areas that have the potential for higher liquids content with approximately $60 million of capital planned for this year. |
– | Plans are to drill 20 operated wells in Texas this year. |
– | Approximately 50 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 Bbls. |
· | Heath Shale |
– | The company holds approximately 90,000 net exploratory leasehold acres in the Heath Shale oil prospect in Montana and expects to drill between 2 and 4 wells this year with capital of approximately $20 million. |
· | Other Opportunities |
– | The company continues to pursue acquisitions of additional leaseholds. Approximately $25 million of capital has been allocated to leasehold acquisitions, focusing on expansion of existing positions and new opportunities. |
– | The remaining forecasted 2012 capital has been allocated to other operated and non-operated opportunities. |
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· | Reserve information |
– | The company’s combined proved natural gas and oil reserves as of Dec. 31 were 586 Bcfe. |
– | Reserve additions replaced annual production however there were approximately 60 Bcfe of negative revisions to last year’s estimates. Approximately 85 percent of the negative revisions were associated with natural gas properties. Revisions of prior estimates, low natural gas prices and a change in strategy to focus on oil properties led to a significant reduction in the number of proved undeveloped reserves associated with natural gas properties. |
– | Oil reserves are 5 percent higher than a year ago primarily the result of approximately 60 percent growth in Bakken reserves. The company’s oil reserve replacement ratio was 175 percent for 2011, excluding revisions. |
– | Natural gas reserves are 15 percent lower primarily for the reasons mentioned previously. The biggest changes occurred in the dry gas fields of Baker and Bowdoin. |
– | With increasing oil reserves as well as higher oil prices, the combined PV10 value of proved oil and natural gas reserves grew by more than 10 percent year-over-year. |
· | Earnings guidance reflects estimated natural gas and oil prices for February through December as follows: |
Natural Gas Index: | |
NYMEX | $2.50 to $3.00 per Mcf |
Crude Oil Index: | |
NYMEX | $95 to $102 per barrel |
Note: Estimated prices do not reflect potential basis differentials. |
· | For 2012, the company has hedged approximately 25 percent to 30 percent of its estimated natural gas production and 65 percent to 70 percent of its estimated oil production. For 2013, the company has hedged 15 percent to 20 percent of its estimated oil production. The hedges that are in place as of Feb. 1 are summarized in the following chart: |
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Commodity | Type | Index | Period Outstanding | Forward Notional Volume (MMBtu/Bbl) | Price (Per MMBtu/Bbl) |
Natural Gas | Swap | NYMEX | 1/12 - 12/12 | 3,477,000 | $6.27 |
Natural Gas | Swap | NYMEX | 1/12 - 12/12 | 1,830,000 | $5.005 |
Natural Gas | Swap | NYMEX | 1/12 - 12/12 | 915,000 | $5.005 |
Natural Gas | Swap | NYMEX | 1/12 - 12/12 | 915,000 | $5.0125 |
Natural Gas | Swap | Ventura | 1/12 - 12/12 | 3,660,000 | $4.87 |
Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 366,000 | $80.00-$87.80 |
Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 366,000 | $80.00-$94.50 |
Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 366,000 | $80.00-$98.36 |
Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 183,000 | $85.00-$102.75 |
Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 183,000 | $85.00-$103.00 |
Crude Oil | Swap | NYMEX | 1/12 - 12/12 | 183,000 | $100.10 |
Crude Oil | Swap | NYMEX | 1/12 - 12/12 | 183,000 | $100.00 |
Crude Oil | Swap | NYMEX | 1/12 - 12/12 | 366,000 | $110.30 |
Crude Oil | Swap | NYMEX | 1/12 - 12/12 | 366,000 | $96.00 |
Crude Oil | Swap | NYMEX | 1/12 - 12/12 | 366,000 | $99.00 |
Crude Oil | Swap | NYMEX | 1/13 - 12/13 | 182,500 | $95.00 |
Crude Oil | Swap | NYMEX | 1/13 - 12/13 | 182,500 | $95.30 |
Crude Oil | Collar | NYMEX | 1/13 - 12/13 | 182,500 | $95.00-$117.00 |
Crude Oil | Collar | NYMEX | 1/13 - 12/13 | 182,500 | $95.00-$117.00 |
Crude Oil | Collar | NYMEX | 1/13 - 12/13 | 365,000 | $90.00-$97.05 |
Natural Gas | Basis Swap | CIG | 1/12 - 12/12 | 2,745,000 | $0.405 |
Natural Gas | Basis Swap | CIG | 1/12 - 12/12 | 732,000 | $0.41 |
Notes: · Ventura is an index pricing point related to Northern Natural Gas Co.’s system; CIG is an index pricing point related to Colorado Interstate Gas Co.’s system. · For all basis swaps, Index prices are below NYMEX prices and are reported as a positive amount in the Price column. |
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Regulated
Electric and Natural Gas Utilities
Electric | ||||||||||||||||
Three Months Ended | Twelve Months Ended | |||||||||||||||
December 31, | December 31, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(Dollars in millions, where applicable) | ||||||||||||||||
Operating revenues | $ | 55.7 | $ | 56.2 | $ | 225.5 | $ | 211.6 | ||||||||
Operating expenses: | ||||||||||||||||
Fuel and purchased power | 15.7 | 17.8 | 64.5 | 63.1 | ||||||||||||
Operation and maintenance | 17.8 | 16.8 | 70.3 | 63.8 | ||||||||||||
Depreciation, depletion and amortization | 8.0 | 7.8 | 32.2 | 27.3 | ||||||||||||
Taxes, other than income | 2.0 | 2.0 | 9.4 | 9.1 | ||||||||||||
43.5 | 44.4 | 176.4 | 163.3 | |||||||||||||
Operating income | 12.2 | 11.8 | 49.1 | 48.3 | ||||||||||||
Earnings | $ | 7.6 | $ | 6.8 | $ | 29.2 | $ | 28.9 | ||||||||
Retail sales (million kWh) | 750.7 | 728.7 | 2,878.9 | 2,785.7 | ||||||||||||
Sales for resale (million kWh) | .1 | 7.2 | 63.9 | 58.3 | ||||||||||||
Average cost of fuel and purchased power per kWh | $ | .020 | $ | .023 | $ | .021 | $ | .021 | ||||||||
Natural Gas Distribution | ||||||||||||||||
Three Months Ended | Twelve Months Ended | |||||||||||||||
December 31, | December 31, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(Dollars in millions) | ||||||||||||||||
Operating revenues | $ | 280.0 | $ | 289.2 | $ | 907.4 | $ | 892.7 | ||||||||
Operating expenses: | ||||||||||||||||
Purchased natural gas sold | 185.8 | 195.0 | 594.6 | 589.3 | ||||||||||||
Operation and maintenance | 34.9 | 34.6 | 137.3 | 137.4 | ||||||||||||
Depreciation, depletion and amortization | 11.2 | 10.9 | 44.6 | 43.0 | ||||||||||||
Taxes, other than income | 12.3 | 12.8 | 48.0 | 47.3 | ||||||||||||
244.2 | 253.3 | 824.5 | 817.0 | |||||||||||||
Operating income | 35.8 | 35.9 | 82.9 | 75.7 | ||||||||||||
Earnings | $ | 20.2 | $ | 23.6 | $ | 38.4 | $ | 37.0 | ||||||||
Volumes (MMdk): | ||||||||||||||||
Sales | 33.6 | 33.9 | 103.3 | 95.5 | ||||||||||||
Transportation | 36.5 | 37.1 | 124.2 | 135.8 | ||||||||||||
Total throughput | 70.1 | 71.0 | 227.5 | 231.3 | ||||||||||||
Degree days (% of normal)* | ||||||||||||||||
Montana-Dakota | 85 | % | 99 | % | 101 | % | 98 | % | ||||||||
Cascade | 101 | % | 96 | % | 103 | % | 96 | % | ||||||||
Intermountain | 102 | % | 95 | % | 107 | % | 100 | % | ||||||||
* Degree days are a measure of the daily temperature-related demand for energy for heating. |
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The combined utility businesses reported earnings of $67.6 million, compared to earnings of $65.9 million in 2010. This increase reflects increased natural gas retail sales volumes and margins and higher electric retail sales margins and volumes. These items were partially offset by higher operation and maintenance expense, largely benefit-related; increased depreciation, depletion and amortization expense, and lower AFUDC.
Fourth quarter combined utility earnings were $27.8 million, compared to $30.4 million for the same period in 2010. The earnings decrease reflects the absence of an income tax benefit of $4.8 million recognized in 2010, as well as higher operation and maintenance expense. Partially offsetting these decreases were increased natural gas retail sales margins and higher electric retail sales margins and volumes.
The following information highlights the key growth strategies, projections and certain assumptions for this segment:
· | The South Dakota Board of Minerals and Environment has approved rules implementing the South Dakota Regional Haze Program that upon approval by the EPA will require the Big Stone Station to install and operate a best available retrofit technology (BART) air quality control system to reduce emissions of particulate matter, sulfur dioxide and nitrogen oxides as early as practicable, but not later than five years after EPA’s approval of the state program. The state program was submitted Jan. 21, 2011. The company’s share of the cost of this air quality control system is estimated at $125 million. The company believes continuing to operate Big Stone Station with the upgrade is the best option. The company intends to seek recovery of costs related to the above matter in electric rates charged to customers. On May 20 the company filed for an advance determination of prudence with the North Dakota Public Service Commission requesting advance determination that the air quality control system is reasonable and prudent. On Jan. 9 a settlement agreement for prudency was filed with NDPSC. An order is expected in first quarter. |
· | On July 7 the company filed for an advance determination of prudence with the North Dakota Public Service Commission on the construction of an 88-MW simple cycle natural gas turbine and associated facilities projected to be in service in 2015. The turbine will be located on currently owned property that is adjacent to the company’s Heskett Generating Station near Mandan, North Dakota and is necessary to meet the capacity requirements of the company’s integrated electric system customers. The capacity will be a partial replacement for third party contract capacity expiring in 2015. Project cost is estimated to be $85.6 million. On Jan. 18 a settlement agreement for prudency was filed with NDPSC and an order is expected in first quarter. |
· | The company is analyzing potential projects for accommodating load growth in its industrial and agricultural sectors with company and customer-owned pipeline facilities designed to serve existing facilities currently served by fuel oil or propane, and to serve new customers. |
· | Currently the company is involved with a number of pipeline projects to enhance the reliability and deliverability of its system in the Pacific Northwest. |
· | The company is pursuing opportunities associated with the potential development of high-voltage transmission lines and system enhancements targeted towards delivery of renewable energy from the wind rich regions that lie within its traditional electric service territory to major market areas. The company has a contract to develop a 30-mile high-voltage power line in southeast North Dakota to move power to the electric grid from a proposed 150-MW wind farm. The proposed project totals approximately $18 million and includes substation upgrades. Construction is underway and the project is expected to be completed by mid 2012. |
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Pipeline and Energy Services | ||||||||||||||||
Three Months Ended | Twelve Months Ended | |||||||||||||||
December 31, | December 31, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(Dollars in millions) | ||||||||||||||||
Operating revenues | $ | 62.9 | $ | 79.5 | $ | 278.3 | $ | 329.8 | ||||||||
Operating expenses: | ||||||||||||||||
Purchased natural gas sold | 25.6 | 34.3 | 125.3 | 153.9 | ||||||||||||
Operation and maintenance | 16.1 | 13.4 | 68.9 | 90.6 | * | |||||||||||
Depreciation, depletion and amortization | 6.2 | 6.6 | 25.5 | 26.0 | ||||||||||||
Taxes, other than income | 2.9 | 3.6 | 13.2 | 13.0 | ||||||||||||
50.8 | 57.9 | 232.9 | 283.5 | |||||||||||||
Operating income | 12.1 | 21.6 | 45.4 | 46.3 | ||||||||||||
Earnings | $ | 6.2 | $ | 12.3 | $ | 23.1 | $ | 23.2 | ||||||||
Transportation volumes (MMdk) | 30.7 | 32.1 | 113.2 | 140.5 | ||||||||||||
Gathering volumes (MMdk) | 15.7 | 19.5 | 66.5 | 77.2 | ||||||||||||
Customer natural gas storage balance (MMdk): | ||||||||||||||||
Beginning of period | 38.5 | 73.8 | 58.8 | 61.5 | ||||||||||||
Net withdrawal | (2.5 | ) | (15.0 | ) | (22.8 | ) | (2.7 | ) | ||||||||
End of period | 36.0 | 58.8 | 36.0 | 58.8 | ||||||||||||
* Reflects a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax). |
Earnings at the pipeline and energy services segment were $23.1 million, compared to earnings of $23.2 million in 2010. This decrease reflects lower storage services revenue, lower transportation volumes, largely lower volumes transported to storage and off-system transportation volumes, as well as lower gathering volumes. Partially offsetting these decreases was lower operation and maintenance expense, primarily related to the absence of a natural gas gathering arbitration charge in 2010.
Fourth quarter earnings for 2011 were $6.2 million, compared to $12.3 million for the comparable prior period. This decrease reflects higher operation and maintenance expense, lower storage services revenue, as well as lower gathering volumes. Higher operation and maintenance expense is primarily related to the absence of an insurance recovery that lowered costs in 2010 related to natural gas storage litigation. The natural gas storage litigation was settled in July 2009.
The following information highlights the key growth strategies, projections and certain assumptions for this segment:
· | The company expects lower customer storage balances this year compared to 2011. In addition, the anticipated divestment of certain natural gas properties and the deferral of certain gas development activity at our exploration and production business are expected to result in gathering volumes being lower in 2012 compared to last year. These declines are expected to be partially offset by higher transportation volumes related to growth projects placed in service in the Bakken area. |
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· | The company continues to pursue expansion of facilities and services offered to customers. Energy development within its geographic region, which includes portions of Colorado, Wyoming, Montana and North Dakota, is expanding, most notably the Bakken of North Dakota and eastern Montana. The company owns an extensive natural gas pipeline system in the Bakken area. Ongoing energy development is expected to have many direct and indirect benefits to this business. |
· | Installation of additional compression at the Charbonneau station was completed and placed into service in September, providing additional firm capacity for producers in the Bakken production area. With some additional modifications, this project has the potential of adding a total of 27 MMcf of firm capacity. |
· | Construction was completed in December on approximately 12 miles of high pressure transmission pipeline providing takeaway capacity from the Garden Creek processing facility in northwestern North Dakota. |
· | Preparations are underway for the construction of approximately 13 miles of high pressure transmission pipeline from the Stateline I and II processing facilities in northwestern North Dakota to deliver gas into the Northern Border Pipeline. The project is expected to be completed by mid 2012. |
· | The company has three natural gas storage fields including the largest storage field in North America located near Baker, Montana. It continues to seek interest in its storage services and is pursuing a project to increase its firm deliverability from the Baker Storage field by 125 MMcf per day. Commitment on approximately 30 percent of the total potential project was received and the additional firm deliverability became available in November. |
Construction
Construction Materials and Contracting | ||||||||||||||||
Three Months Ended | Twelve Months Ended | |||||||||||||||
December 31, | December 31, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(Dollars in millions) | ||||||||||||||||
Operating revenues | $ | 371.7 | $ | 321.1 | $ | 1,510.0 | $ | 1,445.1 | ||||||||
Operating expenses: | ||||||||||||||||
Operation and maintenance | 325.6 | 284.0 | 1,337.4 | 1,260.4 | ||||||||||||
Depreciation, depletion and amortization | 21.2 | 21.1 | 85.5 | 88.3 | ||||||||||||
Taxes, other than income | 7.4 | 6.8 | 36.0 | 33.4 | ||||||||||||
354.2 | 311.9 | 1,458.9 | 1,382.1 | |||||||||||||
Operating income | 17.5 | 9.2 | 51.1 | 63.0 | ||||||||||||
Earnings | $ | 9.7 | $ | 3.8 | $ | 26.4 | $ | 29.6 | ||||||||
Sales (000's): | ||||||||||||||||
Aggregates (tons) | 6,234 | 5,384 | 24,736 | 23,349 | ||||||||||||
Asphalt (tons) | 1,240 | 1,203 | 6,709 | 6,279 | ||||||||||||
Ready-mixed concrete (cubic yards) | 783 | 627 | 2,864 | 2,764 |
The construction materials and contracting segment reported earnings of $26.4 million, compared to $29.6 million for 2010. This decrease reflects lower asphalt oil, ready-mixed concrete and other product line margins. Partially offsetting these decreases were increased construction margins and lower interest expense.
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This segment reported fourth quarter earnings of $9.7 million compared to $3.8 million for the same period in 2010. The increase in earnings was the result of increased construction margins, higher gains on the sale of property, plant and equipment, as well as higher ready-mixed concrete margins and volumes. These increases were partially offset by higher selling, general and administrative costs, primarily payroll-related, and lower asphalt oil margins and volumes.
The following information highlights the key growth strategies, projections and certain assumptions for this segment:
· | Work backlog as of Dec. 31 was approximately $384 million, with 92 percent of construction backlog being public work and private representing 8 percent. Backlog a year ago was approximately $420 million. Examples of projects in work backlog include several highway paving projects, airports, bridge work, reclamation and harbor expansion projects. |
· | The company has green fielded an operation in Williston in the Bakken area of North Dakota and currently has $31 million of backlog in the area. The company is pursuing substantial growth opportunities associated with the Bakken area. |
· | The company is part of a joint venture that was selected as the low bidder on the Port of Long Beach expansion. Its share of the project for this phase is expected to exceed $25 million. It also placed a new approximately 35,000 ton asphalt oil terminal into service in December in Wyoming. The company is the primary cement provider in Hawaii and has the opportunity to supply a portion of the ready-mixed concrete and aggregate related to an approximate $5 billion multi-phased light rail project. |
· | Projected revenues included in the company’s 2012 earnings guidance are in the range of $1.3 billion to $1.4 billion. |
· | The company anticipates margins in 2012 to be higher than 2011 levels. |
· | The company continues to pursue work related to energy projects, such as wind towers, transmission projects, geothermal and refineries. It is also pursuing opportunities for expansion of its existing business lines including initiatives aimed at capturing additional market share and expansion into new markets. |
· | As the country’s 5th largest sand and gravel producer, the company will continue to strategically manage its 1.1 billion tons of aggregate reserves in all its markets, as well as take further advantage of being vertically integrated. |
Construction Services | ||||||||||||||||
Three Months Ended | Twelve Months Ended | |||||||||||||||
December 31, | December 31, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(In millions) | ||||||||||||||||
Operating revenues | $ | 226.7 | $ | 237.3 | $ | 854.4 | $ | 789.1 | ||||||||
Operating expenses: | ||||||||||||||||
Operation and maintenance | 207.3 | 213.6 | 778.5 | 719.7 | ||||||||||||
Depreciation, depletion and amortization | 2.9 | 2.9 | 11.4 | 12.1 | ||||||||||||
Taxes, other than income | 6.3 | 5.5 | 25.4 | 23.9 | ||||||||||||
216.5 | 222.0 | 815.3 | 755.7 | |||||||||||||
Operating income | 10.2 | 15.3 | 39.1 | 33.4 | ||||||||||||
Earnings | $ | 5.8 | $ | 8.9 | $ | 21.6 | $ | 18.0 |
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This segment had earnings of $21.6 million in 2011 compared to $18.0 million in 2010. The earnings increase reflects higher workloads and margins in the Western region, higher equipment sales and rental margins, as well as decreased general and administrative expense. The earnings increase was partially offset by lower workloads and margins in the Mountain region, as well as lower margins in the Central region.
Fourth quarter earnings for this segment were $5.8 million, compared to $8.9 million for the comparable prior period. The earnings decrease reflects lower margins largely in the Western and Mountain regions. Partially offsetting the earnings decrease were higher equipment sales and rental margins, as well as decreased general and administrative expense, largely lower payroll-related costs.
The following information highlights the key growth strategies, projections and certain assumptions for this segment:
· | Work backlog as of Dec. 31 was approximately $308 million, compared to approximately $373 million a year ago. The backlog includes a variety of projects such as substation and line construction, solar and other commercial, institutional and industrial projects including refinery work. |
· | Projected revenues included in the company’s 2012 earnings guidance are in the range of $700 million to $800 million. |
· | The company anticipates margins in 2012 to be higher than 2011 levels. |
· | The company is pursuing expansion in high-voltage transmission and substation construction, renewable resource construction, governmental facilities, refinery turnaround projects and utility service work. |
Other |
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(In millions) | ||||||||||||||||
Operating revenues | $ | 3.5 | $ | .9 | $ | 11.4 | $ | 7.7 | ||||||||
Operating expenses: | ||||||||||||||||
Operation and maintenance | (1.8 | ) | (.7 | ) | 4.7 | 4.8 | ||||||||||
Depreciation, depletion and amortization | .4 | .4 | 1.6 | 1.6 | ||||||||||||
Taxes, other than income | --- | .2 | .1 | .5 | ||||||||||||
(1.4 | ) | (.1 | ) | 6.4 | 6.9 | |||||||||||
Operating income | 4.9 | 1.0 | 5.0 | .8 | ||||||||||||
Income from continuing operations | 4.2 | 16.0 | 6.2 | 21.0 | ||||||||||||
Loss from discontinued operations, net of tax | (13.1 | )* | (3.3 | ) | (12.9 | )* | (3.3 | ) | ||||||||
Earnings | $ | (8.9 | ) | $ | 12.7 | ** | $ | (6.7 | ) | $ | 17.7 | ** | ||||
* Reflects an arbitration charge of $13.0 million after tax related to a guarantee of a construction contract. ** Includes a gain on the sale of the Brazilian transmission lines of $13.8 million after tax. |
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A loss of $6.7 million was reported for the year compared to 2010 earnings of $17.7 million, which included a fourth quarter gain on the sale of the Brazilian transmission lines of $13.8 million after tax. The loss from discontinued operations in fourth quarter 2011 includes an accrual of $13.0 million after tax related to a demand for payment of an arbitration award under a guarantee which provided for performance of a construction contract by one of the companies included in the 2007 sale of the domestic power production business. The company intends to contest the demand for payment under the guarantee. Please refer to Note 18 of the company’s most recent Form 10-Q filed with the Securities and Exchange Commission for previous disclosure regarding this matter.
Risk Factors and Cautionary Statements that May Affect Future Results
The information in this release includes certain forward-looking statements, including earnings per share guidance and statements by the president and chief executive officer of MDU Resources, within the meaning of Section 21E of the Securities Exchange Act of 1934. Although the company believes that its expectations are based on reasonable assumptions, actual results may differ materially. Following are important factors that could cause actual results or outcomes for the company to differ materially from those discussed in forward-looking statements.
· | The company’s exploration and production and pipeline and energy services businesses are dependent on factors, including commodity prices and commodity price basis differentials, which are subject to various external influences that cannot be controlled. |
· | The regulatory approval, permitting, construction, startup and operation of power generation facilities may involve unanticipated changes or delays that could negatively impact the company’s business and its results of operations and cash flows. |
· | Economic volatility affects the company’s operations, as well as the demand for its products and services and the value of its investments and investment returns including its pension and other postretirement benefit plans and, may have a negative impact on the company’s future revenues and cash flows. |
· | The company relies on financing sources and capital markets. Access to these markets may be adversely affected by factors beyond the company’s control. If the company is unable to obtain economic financing in the future, the company’s ability to execute its business plans, make capital expenditures or pursue acquisitions that the company may otherwise rely on for future growth could be impaired. As a result, the market value of the company’s common stock may be adversely affected. If the company issues a substantial amount of common stock it could have a dilutive effect on its existing shareholders. |
· | The company is exposed to credit risk and the risk of loss resulting from the nonpayment and/or nonperformance by the company’s customers and counterparties. |
· | The backlogs at the company’s construction materials and contracting and construction services businesses are subject to delay or cancellation and may not be realized. |
· | Actual quantities of recoverable natural gas and oil reserves and discounted future net cash flows from those reserves may vary significantly from estimated amounts. |
· | The company’s operations are subject to environmental laws and regulations that may increase costs of operations, impact or limit business plans, or expose the company to environmental liabilities. |
· | Global climate change initiatives to reduce greenhouse gas emissions could adversely impact the company’s electric generation operations. |
· | The company is subject to government regulations that may delay and/or have a negative impact on its business and its results of operations and cash flows. Statutory and regulatory requirements also may limit another party’s ability to acquire the company. |
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· | Weather conditions can adversely affect the company’s operations and revenues and cash flows. |
· | Competition is increasing in all of the company’s businesses. |
· | The company could be subject to limitations on its ability to pay dividends. |
· | An increase in costs related to obligations under multiemployer pension plans could have a material negative effect on the company’s results of operations and cash flows. |
· | The company's operations may be negatively impacted by cyber attacks or acts of terrorism. |
· | Other factors that could cause actual results or outcomes for the company to differ materially from those discussed in forward-looking statements include: |
o | Acquisition, disposal and impairments of assets or facilities. |
o | Changes in operation, performance and construction of plant facilities or other assets. |
o | Changes in present or prospective generation. |
o | The ability to obtain adequate and timely cost recovery for the company’s regulated operations through regulatory proceedings. |
o | The availability of economic expansion or development opportunities. |
o | Population growth rates and demographic patterns. |
o | Market demand for, available supplies of, and/or costs of, energy- and construction-related products and services. |
o | The cyclical nature of large construction projects at certain operations. |
o | Changes in tax rates or policies. |
o | Unanticipated project delays or changes in project costs, including related energy costs. |
o | Unanticipated changes in operating expenses or capital expenditures. |
o | Labor negotiations or disputes. |
o | Inability of the various contract counterparties to meet their contractual obligations. |
o | Changes in accounting principles and/or the application of such principles to the company. |
o | Changes in technology. |
o | Changes in legal or regulatory proceedings. |
o | The ability to effectively integrate the operations and the internal controls of acquired companies. |
o | The ability to attract and retain skilled labor and key personnel. |
o | Increases in employee and retiree benefit costs and funding requirements. |
For a further discussion of these risk factors and cautionary statements, refer to Item 1A – Risk Factors in the company’s most recent Form 10-K and Form 10-Q.
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MDU Resources Group, Inc. | ||||||||||||||||
Three Months Ended | Twelve Months Ended | |||||||||||||||
December 31, | December 31, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(In millions, except per share amounts) (Unaudited) | ||||||||||||||||
Operating revenues | $ | 1,065.7 | $ | 1,042.6 | $ | 4,050.5 | $ | 3,909.7 | ||||||||
Operating expenses: | ||||||||||||||||
Fuel and purchased power | 15.7 | 17.8 | 64.5 | 63.1 | ||||||||||||
Purchased natural gas sold | 175.9 | 185.4 | 572.2 | 567.8 | ||||||||||||
Operation and maintenance | 619.7 | 585.5 | 2,491.1 | 2,375.9 | ||||||||||||
Depreciation, depletion and amortization | 86.5 | 83.8 | 343.4 | 328.8 | ||||||||||||
Taxes, other than income | 41.3 | 39.9 | 172.9 | 163.4 | ||||||||||||
939.1 | 912.4 | 3,644.1 | 3,499.0 | |||||||||||||
Operating income | 126.6 | 130.2 | 406.4 | 410.7 | ||||||||||||
Earnings from equity method investments | 2.4 | 23.8 | 4.7 | 30.8 | ||||||||||||
Other income | 1.4 | 1.1 | 6.5 | 8.0 | ||||||||||||
Interest expense | 19.7 | 21.1 | 81.4 | 83.0 | ||||||||||||
Income before income taxes | 110.7 | 134.0 | 336.2 | 366.5 | ||||||||||||
Income taxes | 36.6 | 41.7 | 110.3 | 122.5 | ||||||||||||
Income from continuing operations | 74.1 | 92.3 | 225.9 | 244.0 | ||||||||||||
Loss from discontinued operations, net of tax | (13.1 | ) | (3.3 | ) | (12.9 | ) | (3.3 | ) | ||||||||
Net income | 61.0 | 89.0 | 213.0 | 240.7 | ||||||||||||
Dividends declared on preferred stocks | .2 | .2 | .7 | .7 | ||||||||||||
Earnings on common stock | $ | 60.8 | $ | 88.8 | $ | 212.3 | $ | 240.0 | ||||||||
Earnings per common share – basic: | ||||||||||||||||
Earnings before discontinued operations | $ | .39 | $ | .49 | $ | 1.19 | $ | 1.29 | ||||||||
Discontinued operations, net of tax | (.07 | ) | (.02 | ) | (.07 | ) | (.01 | ) | ||||||||
Earnings per common share – basic | $ | .32 | $ | .47 | $ | 1.12 | $ | 1.28 | ||||||||
Earnings per common share – diluted: | ||||||||||||||||
Earnings before discontinued operations | $ | .39 | $ | .49 | $ | 1.19 | $ | 1.29 | ||||||||
Discontinued operations, net of tax | (.07 | ) | (.02 | ) | (.07 | ) | (.02 | ) | ||||||||
Earnings per common share – diluted | $ | .32 | $ | .47 | $ | 1.12 | $ | 1.27 | ||||||||
Dividends declared per common share | $ | .1675 | $ | .1625 | $ | .6550 | $ | .6350 | ||||||||
Weighted average common shares outstanding – basic | 188.8 | 188.3 | 188.8 | 188.1 | ||||||||||||
Weighted average common shares outstanding – diluted | 188.9 | 188.4 | 188.9 | 188.2 |
Note: Three months and twelve months ended Dec. 31, 2011 discontinued operations reflect the effects of an arbitration charge of $21.0 million ($13.0 million after tax) related to a guarantee of a construction contract. Three months and twelve months ended Dec. 31, 2010 reflect the effects of a gain on the sale of the Brazilian transmission assets of $22.7 million ($13.8 million after tax). Twelve months ended Dec. 31, 2010 results also reflect the effects of a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax).
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Twelve Months Ended December 31, | ||||||||
2011 | 2010 | |||||||
(Unaudited) | ||||||||
Other Financial Data | ||||||||
Book value per common share | $ | 14.62 | $ | 14.22 | ||||
Market price per common share | $ | 21.46 | $ | 20.27 | ||||
Dividend yield (indicated annual rate) | 3.1 | % | 3.2 | % | ||||
Price/earnings ratio* | 19.2 | x | 16.0 | x | ||||
Market value as a percent of book value | 146.8 | % | 142.5 | % | ||||
Return on average common equity* | 7.8 | % | 9.1 | % | ||||
Total assets** | $ | 6.6 | $ | 6.3 | ||||
Total equity** | $ | 2.8 | $ | 2.7 | ||||
Total debt ** | $ | 1.4 | $ | 1.5 | ||||
Capitalization ratios: | ||||||||
Total equity | 66 | % | 64 | % | ||||
Total debt | 34 | 36 | ||||||
100 | % | 100 | % | |||||
*Represents 12 months ended
** In billions
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