MDU Resources Reports Third Quarter Earnings, Announces Sale of Exploration and Production Assets

BISMARCK, N.D.–(BUSINESS WIRE)–MDU Resources Group, Inc. (NYSE:MDU) today reported third quarter consolidated adjusted earnings of $74.9 million, or 38 cents per share, compared to $68.2 million, or 35 cents per share for the third quarter of 2014. On a Generally Accepted Accounting Principles basis the company reported a loss of $139.6 million, or 72 cents per share, compared to third quarter 2014 earnings of $103.0 million, or 53 cents per share.

Adjusted earnings for the nine months ended Sept. 30 were $131.4 million, or 67 cents per share, compared to $137.7 million, or 72 cents per share a year ago. On a GAAP basis the company reported a loss of $675.5 million, or $3.47 per share, compared to earnings of $213.5 million, or $1.11 per share in 2014.

The company also announced that it recently entered into five purchase and sale agreements and closed on one of the agreements in October, for the sale of the oil and natural gas assets held by its indirect subsidiary, Fidelity Exploration & Production Company. The other four sale agreements are expected to close before year-end. The aggregate sale proceeds from the five agreements and estimated tax benefits are expected to be approximately $450 million. Debt repayment is planned as the primary use of funds. The company has one remaining property that it continues to market, which represents less than 10 percent of total year-to-date production.

“We are pleased to be nearly complete with the sale process for our oil and natural gas assets,” said David L. Goodin, president and CEO of MDU Resources. “The sale prices are in line with current and prospective market conditions, and exiting the exploration and production business will allow us to focus more fully on our remaining businesses.

“Our consolidated adjusted earnings per share for the quarter were 9 percent higher than last year. Our electric utility had a good quarter with 7 percent sales growth, partially offset by a normal seasonal loss for our natural gas business, and at our pipeline and energy services group we continued to see commodity price challenges. Our construction materials business had record earnings that were 25 percent higher on 4 percent revenue growth with operating income improving across all regions. While our construction services business had lower workloads in the quarter, backlog additions were strong.”

Because of the company’s strategic decision to market the exploration and production business, adjusted earnings in this release are defined as results from its utility, pipeline and energy services, and construction businesses. Adjusted earnings exclude results for its exploration and production business. GAAP earnings are all-in. Consolidated adjusted earnings are a non-GAAP measure. For an explanation of non-GAAP earnings adjustments, see the Reconciliation of GAAP to Adjusted Earnings and the Use of Non-GAAP Financial Measures sections in this press release.

Business Unit Results
Electric utility operations reported earnings of $12.6 million, driven by an increase in electric sales spread across all customer classes. The utility also benefited from a generation rider in North Dakota that took effect in January, as well as increased allowance for funds used during construction. The natural gas business experienced a normal seasonal loss.

The pipeline and energy services business posted an adjusted loss of $1.2 million, compared to adjusted earnings of $5.1 million a year ago. Earnings were impacted by the operating results of the refinery, which began commercial operations in May. The company’s after-tax portion of the refinery’s loss was $5.8 million for the quarter the result of challenging market conditions including low diesel and naphtha prices along with historically narrow local Bakken basis differentials. A year ago the company had a loss of $700,000 related to the refinery. Earnings also were impacted by lower realized prices on its percentage of proceeds contract and volumes at the Pronghorn facility. These impacts were partially offset by 19 percent higher transportation volumes.

The construction materials business had record earnings for the quarter of $68.8 million. Margins increased across all product lines. Backlog at Sept. 30 was $533 million compared to $476 million a year ago. The construction services group experienced decreased workloads compared to 2014 due to completing several higher-margin large projects a year ago. The business continues to rebuild backlog, which at the end of the quarter totaled $458 million compared to $348 million in 2014.

2015 Guidance
The company reaffirmed its 2015 guidance for adjusted earnings in the range of 85 cents to $1.00 per share. Adjusted earnings per share guidance includes results from the company’s utility, pipeline and energy services, and construction businesses and excludes results for its exploration and production business as well as other adjustments noted in the earnings reconciliation table in this release. Updated GAAP guidance, which is all-in, is expected to be a loss per share in the range of $3.15 to $3.30.

Conference Call
The company will host a webcast at 10 a.m. EST Nov. 3, to discuss third quarter 2015 results. The event can be accessed at www.mdu.com. Webcast and audio replays will be available. The dial-in number for audio replay is 855-859-2056, or 404-537-3406 for international callers, conference ID 57967847.

About MDU Resources
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, pipeline and energy services, and construction materials and services. For more information about MDU Resources, see the company’s website at www.mdu.com or contact the Investor Relations Department at investor@mduresources.com.

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.

On a consolidated basis, the following information highlights the key strategies, projections and certain assumptions for the company:

• Adjusted earnings per share for 2015 are projected in the range of 85 cents to $1.00. Adjusted earnings excludes the effects of the exploration and production business as well as other adjustments noted in the earnings reconciliation table in this release.
• GAAP guidance for 2015 is a loss per share in the range of $3.15 to $3.30.
• The company’s long-term compound annual growth goals on adjusted earnings per share from operations are in the range of 7 to 10 percent.
• The company continually seeks opportunities to expand through organic growth opportunities and strategic acquisitions.
• The company focuses on creating value through vertical integration between its business units.
• Estimated capital expenditures for 2015 are noted in the following table. An updated five-year forecast will be provided in mid-November to include the years 2016 through 2020.

The combined utility businesses reported earnings of $300,000 in the third quarter of 2015, compared to a loss of $3.1 million for the same period in 2014. This increase reflects record earnings at the electric business with higher electric retail sales margins, including 7 percent higher volumes spread across all customer classes. The increase also reflects higher other income, largely related to AFUDC, offset in part by higher depreciation, depletion and amortization expense. Natural gas distribution reported a loss comparable to the same period in 2014. Lower operation and maintenance expense, largely payroll costs and contract services, and natural gas retail rate increases were largely offset by higher depreciation, depletion and amortization expense and lower natural gas sales volumes. The combined utility had higher depreciation, depletion and amortization expense because of plant additions, which are included for potential recovery in rate cases.

The following information highlights the key growth strategies, projections and certain assumptions for this segment:

• Organic growth opportunities are expected to result in substantial rate base growth.
• Growth Projects/Opportunities
  • Investments of approximately $56 million are being made in 2015 to serve growth in the electric and natural gas customer base associated with the Bakken oil development.
  • The company, along with a partner, expects to build a 345-kilovolt transmission line from Ellendale, North Dakota, to Big Stone City, South Dakota, about 160 miles. The company’s share of the cost is estimated at approximately $205 million including development costs and substation upgrade costs. The project has been approved as a Midcontinent Independent System Operator multivalue project. A route application was filed in August 2013 with the state of South Dakota and in October 2013 with the state of North Dakota. A route permit was approved July 10, 2014, in North Dakota and Aug. 13, 2014, in South Dakota. The South Dakota route permit was appealed and a district court ruled in favor of the project. The district court decision has been appealed to the South Dakota Supreme Court. More than 90 percent of the necessary easements have been secured. The company expects the project to be completed in 2019.
  • The company is reviewing potential future generation options and is considering a large scale resource. The Integrated Resource Plan filed in July includes a 200 MW resource addition in the 2020 timeframe.
  • The company is analyzing potential projects for accommodating load growth in its industrial and agricultural sectors, with pipelines designed to serve existing facilities utilizing fuel oil or propane, and to serve new customers.
  • The company is involved with a number of pipeline projects to enhance the reliability and deliverability of its system.
  • The company also is focused on growth through potential mergers and acquisitions.
  • The company is evaluating the final Clean Power Plan rule published by the EPA in October, which requires existing fossil fuel-fired electric generation facilities to reduce carbon dioxide emissions. It is unknown at this time what each state will require for emissions limits or reductions from each of the company’s owned and jointly owned fossil fuel-fired electric generating units. Compliance costs will become clearer as final state plans are completed and submitted to the EPA by Sept. 6, 2018.
• Regulatory actions

Completed Cases:

• Aug. 11, 2014, the company filed an application with the Montana Public Service Commission for a natural gas rate increase of approximately $3.0 million annually, or 3.6 percent. The requested increase includes costs associated with the increased investment in facilities and associated depreciation, taxes and operation and maintenance expenses. An interim increase of $2.0 million annually was approved and implemented for service effective Feb. 6, subject to refund. The commission approved a $2.5 million annual increase effective with service on or after May 20, 2015.
• Oct. 3, 2014, the company filed an application with the Wyoming Public Service Commission for a natural gas rate increase of approximately $788,000 annually, or 4.1 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities and associated depreciation, taxes and operation and maintenance expenses. The commission approved an increase of $501,000 annually, which was implemented June 1, 2015.
• Nov. 14 the company filed an application with the North Dakota Public Service Commission for approval to implement the rate adjustment associated with the electric generation resource recovery rider previously approved by the commission. The rider was established to recover costs associated with new generation such as the Heskett III 88-megawatt natural gas combustion turbine. The commission approved a rate adjustment of $5.3 million annually, which was implemented Jan. 9.
• Dec. 22 the company filed for advanced determination of prudence with the NDPSC on the Thunder Spirit Wind project. The commission approved the ADP and June 30 issued a certificate of public convenience and necessity. The company has an agreement to purchase the project, which includes 43 wind turbines totaling 107.5 MW of electric generation, at a total cost of approximately $220 million including purchase price, internal costs and AFUDC. ALLETE Clean Energy is developing the project, with an expected completion in December 2015.
• April 10 the company filed a required annual update with the NDPSC to the electric rate environmental cost recovery rider for a total of $8.1 million for rates effective July 1, consistent with revenues previously included in the rider. The requested recovery includes costs for the Big Stone and Lewis & Clark Stations’ environmental upgrades. The commission approved the requested rider update and the new rates were implemented July 1.

Pending Cases:

• Feb. 6 the company filed an application with the NDPSC for a natural gas rate increase of approximately $4.3 million annually, or 3.4 percent above current rates. The requested increase includes costs associated with the increased investment in facilities and associated depreciation, taxes and operation and maintenance expenses. An interim increase of $4.3 million annually was implemented for service effective April 7, subject to refund. A settlement agreement was filed Aug. 26 for a $2.6 million annual increase. A hearing was held Aug. 31.
• March 31 the company filed an application with the Oregon Public Utility Commission for a natural gas rate increase of approximately $3.6 million, or 5.1 percent above current rates. The requested increase includes costs associated with the increased investment in facilities and associated depreciation, taxes and operation and maintenance expenses, as well as environmental remediation expenses. A settlement in principle has been reached and is expected to be filed in the near term.
• June 25 the company filed an application with the MTPSC for an electric rate increase of approximately $11.8 million annually, or 21.1 percent above current rates. The requested increase includes costs associated with environmental upgrades to generation facilities, and the addition and/or replacement of capacity and energy requirements and transmission facilities along with associated depreciation, taxes and operation and maintenance expenses. An interim increase of $11.0 million annually, subject to refund, was requested. The commission has nine months in which to render a decision on the application. A hearing is scheduled for Feb. 9.
• June 30 the company filed an application with the South Dakota Public Utilities Commission for an electric rate increase of approximately $2.7 million, or 19.2 percent above current rates. The requested increase includes costs associated with environmental upgrades to generation facilities, and the addition and/or replacement of capacity and energy requirements and transmission facilities along with associated depreciation, taxes and operation and maintenance expenses. The commission has six months in which to render a decision on the application.
• June 30 the company filed an application with the SDPUC for a natural gas rate increase of approximately $1.5 million annually, or 3.1 percent above current rates. The request includes costs for increased operating expenses along with increased investment in facilities, including related depreciation expense and taxes, partially offset by an increase in customers and throughput. The commission has six months in which to render a decision on the application.
• Sept. 1, and as amended Oct. 5, the company submitted an update to a tracker-type mechanism with the Midcontinent Independent System Operator reflecting a revenue requirement of $3.8 million to be effective Jan. 1. The filing recovers investment for costs associated with transmission investments qualified for sharing under MISO’s Transmission Expansion Plan, such as the Big Stone to South Ellendale Multi-Value Project.
• Sept. 30 the company filed an application with the Minnesota Public Utilities Commission for a natural gas rate increase of approximately $1.6 million annually, or 6.4 percent above current rates. The requested increase includes costs for increased operating expenses along with increased investment in facilities, including related depreciation expense and taxes. An interim increase of $1.5 million annually, subject to refund, was requested to be effective Jan. 1.
• Oct. 21 the company filed an application with the NDPSC for an update to the Generation Resource Recovery Rider and requested a Renewable Resource Cost Adjustment Rider effective Jan. 1. The combined filing totaled $25.3 million with $20.0 million incremental to current rates. The generation rider recovers investment in the Heskett III natural gas fired turbine put into service August 2014 as well as the Lewis & Clark Reciprocating Internal Combustion Engines generating units anticipated to be in service in December. Recovery of the Thunder Spirit Wind Farm, also anticipated to be online in December, is requested via a new renewable rider.

Expected Filings:

• June 24 the company filed an expedited application with the Washington Utilities and Transportation Commission for a natural gas rate increase of approximately $3.9 million annually, or 1.6 percent above current rates. The expedited request was withdrawn after the commission indicated its intention to suspend the filing. The company expects to file a full application by year-end.
• The company expects to file an electric rate case in Wyoming in early 2016.

This segment reported an adjusted loss of $1.2 million in the third quarter of 2015, compared to adjusted earnings of $5.1 million for the same period in 2014. Earnings were impacted by the results of the refinery where the company’s after-tax portion of the loss was $5.8 million for the quarter, the result of challenging market conditions including lower diesel and naphtha prices along with historically narrow local Bakken basis differentials. A year ago the company had a loss of $700,000 related to the refinery. The decrease also reflects lower realized prices on its percentage of proceeds contract and volumes at Pronghorn partially offset by higher transportation volumes.

This segment recorded a GAAP loss of $9.5 million in the third quarter of 2015 including an $8.7 million impairment related primarily to a non-strategic natural gas gathering asset that the company is negotiating to sell. GAAP earnings were $5.1 million for the same period a year ago.

The following information highlights the key growth strategies, projections and certain assumptions for this segment:

• The company is focused on improving existing operations and accelerating growth to become the leading pipeline company and midstream provider in its operational areas, including expanding existing facilities and services. The company is also evaluating expansion into other basins.
• The company signed agreements this year to complete two expansion projects, the North Badlands expansion and the Northwest North Dakota expansion. The North Badlands project includes a 4-mile loop of the Garden Creek II pipeline and measurement and associated facilities, expected to be in service in fall of 2016. The Northwest North Dakota project includes modification of existing compression, a new unit and re-cylindering, expected to be in service the summer of 2016.
• The company has an agreement with an anchor shipper to construct a pipeline to connect the Demicks Lake gas processing plant in northwestern North Dakota to deliver natural gas into a new interconnect with the Northern Border Pipeline. Project costs are estimated to be $50 million to $60 million. The project has been delayed by the plant owner.
• The planned Wind Ridge Pipeline project, a 95-mile natural gas pipeline designed to deliver approximately 90 million cubic feet per day to a fertilizer plant near Spiritwood, North Dakota, has been canceled with the fertilizer plant developer’s decision to not build the plant. WBI Energy has been reimbursed for all costs incurred related to project development.
• The company, in conjunction with Calumet Specialty Products Partners, L.P., owns Dakota Prairie Refining, LLC, operating a 20,000-barrel-per-day refinery in southwestern North Dakota. The refinery processes Bakken crude into diesel, which is marketed within the Bakken region. Other byproducts, naphtha and atmospheric tower bottoms, are transported to other areas. The production slate includes approximately 7,000 barrels per day of diesel, 6,500 BPD of naphtha and 6,000 BPD of ATBs. Company crude oil purchases for the intake have been at a discount to West Texas Intermediate. However, this discount has been much narrower than anticipated because of market conditions in the Bakken. Clearbrook and Guernsey are two crude pricing points that are considered when determining purchase prices as well as other local market indicators. Diesel is sold locally at the refinery rack and DPR posts a price based on market conditions. DPR posted diesel prices were in the $60 to $80 per barrel range during the third quarter. Naphtha is being railed into Canada to be used as a diluent for tar sands production and is tied to C5 pricing differentials to WTI.

The combined construction businesses reported earnings of $73.5 million in the third quarter of 2015, compared to $65.1 million in 2014. The increase reflects record earnings at the materials group with higher margins across all product lines, higher volumes for all products except ready-mix, and higher construction revenues and margins. These increases were offset in part by the services group’s lower construction margins and workloads in the Western Region and lower equipment sales and rental margins, as well as the materials group’s higher effective tax rates.

The following information highlights the key growth strategies, projections and certain assumptions for the construction segments:

• The construction materials business’ approximate work backlog as of Sept. 30 was $533 million, compared to $476 million a year ago. Private work represents 14 percent of construction backlog and public work represents 86 percent of backlog. The Sept. 30 approximate work backlog at construction services was $458 million, compared to $348 million a year ago. The backlogs include a variety of projects, such as highway grading, paving and underground projects, airports, bridge work, subdivisions, substation and line construction, solar projects and other commercial, institutional and industrial projects, including petrochemical work.
• Projected revenues included in the company’s 2015 earnings guidance are in the range of $1.8 billion to $2.0 billion for construction materials and $850 million to $950 million for construction services.
• The company anticipates margins in 2015 to be higher at construction materials and lower at construction services compared to 2014 margins.
• The company continues to pursue opportunities for expansion in energy projects, such as petrochemical, transmission, substations, utility services, solar, wind towers and geothermal. Initiatives are aimed at capturing additional market share and expanding into new markets.
• As the country’s fifth-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.

The loss increased $300,000, primarily the result of higher insurance costs partially offset by lower income taxes. Included in Other are operation and maintenance expense and interest expense previously allocated to the exploration and production business that do not meet the criteria for income (loss) from discontinued operations, the majority of which is expected to be reduced following the sale of the exploration and production business and the repayment of debt.

The results of operations for the company’s exploration and production business, except certain general and administrative costs and interest expense that do not meet the criteria for income (loss) from discontinued operations, along with a benefit related to the vacation of an arbitration award in 2014 related to Centennial Resources, are included in the earnings (loss) from discontinued operations.

The company’s discontinued operations reported a loss of $202.6 million in the third quarter of 2015, compared to income of $38.5 million in 2014. The decrease reflects a $224.4 million after-tax fair value impairment of the exploration and production assets. The decrease also reflects 54 percent lower average realized oil prices, 33 percent lower oil production due to 2014 divestments and field declines and a lower unrealized gain on commodity derivatives. Partially offsetting these decreases were lower depreciation, depletion and amortization expense and lease operating expenses.

The following table provides additional information on the company’s discontinued operations:

Use of Non-GAAP Financial Measures
The company, in addition to presenting its earnings information in conformity with GAAP, has provided non-GAAP earnings data that reflect adjustments to exclude:

Three months ended September 30, 2015 and 2014:

• Exploration and production business loss of $206.2 million and earnings of $34.8 million in 2015 and 2014, respectively.
• Natural gas gathering assets impairment of $8.7 million after tax in 2015 primarily related to a non-strategic asset that the company is negotiating to sell.
• Variance related to the absence of start-up costs of $400,000 after tax for the company’s portion of Dakota Prairie refinery in 2015.

Nine months ended September 30, 2015 and 2014:

• Exploration and production business loss of $790.4 million and earnings of $75.3 million in 2015 and 2014, respectively.
• Natural gas gathering assets impairments of $10.6 million after tax in 2015.
• Additional start-up costs of $3.0 million after tax for the company’s portion of Dakota Prairie refinery in 2015.
• A multiemployer pension plan withdrawal liability of $1.5 million after tax in 2015.
• Underperforming non-strategic asset loss of $1.4 million after tax in 2015.
• Earnings of $500,000 in 2014 from discontinued operations related to other operations.

The company believes that these non-GAAP financial measures are useful to investors because the items excluded are not indicative of the company’s continuing operating results. Also, the company’s management uses these non-GAAP financial measures as indicators for planning and forecasting future periods. The presentation of this additional information is not meant to be considered a substitute for financial measures prepared in accordance with GAAP.

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 CEO 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, that are subject to various external influences that cannot be controlled.
• Actual quantities of recoverable oil, natural gas liquids and natural gas reserves and discounted future net cash flows from those reserves may vary significantly from estimated amounts. There is a risk that changes in estimates of proved reserve quantities or other factors including low oil and natural gas prices, could result in future noncash write-downs of the company’s exploration and production business.
• The regulatory approval, permitting, construction, startup and/or operation of power generation facilities may involve unanticipated events or delays that could negatively impact the company’s business and its results of operations and cash flows.
• The operation of Dakota Prairie refinery may involve unanticipated events 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.
• 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.
• Initiatives to reduce greenhouse gas emissions could adversely impact the company’s 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.
• 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.
• While the company entered into purchase and sale agreements to sell the vast majority of Fidelity Exploration & Production Company’s assets comprising greater than 90 percent of production for the nine months ended September 30, 2015, and is currently marketing the remaining assets of Fidelity, there is no assurance that a sale of all marketed assets will be successful.
• Other factors that could cause actual results or outcomes for the company to differ materially from those discussed in forward-looking statements include:
  • Acquisition, disposal and impairments of assets or facilities.
  • Changes in operation, performance and construction of plant facilities or other assets.
  • Changes in present or prospective generation.
  • The ability to obtain adequate and timely cost recovery for the company’s regulated operations through regulatory proceedings.
  • The availability of economic expansion or development opportunities.
  • Population growth rates and demographic patterns.
  • Market demand for, available supplies of, and/or costs of, energy- and construction-related products and services.
  • The cyclical nature of large construction projects at certain operations.
  • Changes in tax rates or policies.
  • Unanticipated project delays or changes in project costs, including related energy costs.
  • Unanticipated changes in operating expenses or capital expenditures.
  • Labor negotiations or disputes.
  • Inability of the various contract counterparties to meet their contractual obligations.
  • Changes in accounting principles and/or the application of such principles to the company.
  • Changes in technology.
  • Changes in legal or regulatory proceedings.
  • The ability to effectively integrate the operations and the internal controls of acquired companies.
  • The ability to attract and retain skilled labor and key personnel.
  • 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.