News Column

MDU RESOURCES GROUP INC - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

August 8, 2014

Overview

The Company's strategy is to apply its expertise in energy and transportation infrastructure industries to increase market share, increase profitability and enhance shareholder value through:



Organic growth as well as a continued disciplined approach to the acquisition

of well-managed companies and properties

The elimination of system-wide cost redundancies through increased focus on

integration of operations and standardization and consolidation of various

support services and functions across companies within the organization

The development of projects that are accretive to earnings per share and

return on invested capital

The Company has capabilities to fund its growth and operations through various sources, including internally generated funds, commercial paper facilities, revolving credit facilities and the issuance from time to time of debt and equity securities. For more information on the Company's net capital expenditures, see Liquidity and Capital Commitments.

The key strategies for each of the Company's business segments and certain related business challenges are summarized below. For a summary of the Company's business segments, see Note 18.

Key Strategies and Challenges Electric and Natural Gas Distribution Strategy Provide safe and reliable competitively priced energy and related services to customers. The electric and natural gas distribution segments continually seek opportunities to retain, grow and expand their customer base through extensions of existing operations, including building and upgrading electric generation and transmission and natural gas systems, and through selected acquisitions of companies and properties at prices that will provide stable cash flows and an opportunity for the Company to earn a competitive return on investment. Challenges Both segments are subject to extensive regulation in the state jurisdictions where they conduct operations with respect to costs and permitted returns on investment as well as subject to certain operational, system integrity and environmental regulations. These regulations can require substantial investment to upgrade facilities. The ability of these segments to grow through acquisitions is subject to significant competition. In addition, the ability of both segments to grow service territory and customer base is affected by the economic environment of the markets served and competition from other energy providers and fuels. The construction of any new electric generating facilities, transmission lines and other service facilities are subject to increasing cost and lead time, extensive permitting procedures, and federal and state legislative and regulatory initiatives, which will necessitate increases in electric energy prices. Legislative and regulatory initiatives to increase renewable energy resources and reduce GHG emissions could impact the price and demand for electricity and natural gas. Pipeline and Energy Services Strategy Utilize the segment's existing expertise in energy infrastructure and related services to increase market share and profitability through optimization of existing operations, internal growth, investments in and acquisitions of energy-related assets and companies. Incremental and new growth opportunities include: access to new energy sources for storage, gathering and transportation services; expansion of existing gathering, transmission and storage facilities; incremental expansion of pipeline capacity; expansion of midstream business to include liquid pipelines and processing/refining activities; and expansion of related energy services. Challenges Challenges for this segment include: energy price volatility; tight natural gas basis differentials; environmental and regulatory requirements; recruitment and retention of a skilled workforce; and competition from other pipeline and energy services companies. Exploration and Production Strategy Apply technology and utilize existing exploration and production expertise, with a focus on operated properties, to increase production and reserves from existing leaseholds, and to seek additional reserves and production opportunities both in new and existing areas to further expand the segment's asset base. By optimizing existing operations and taking advantage of new and incremental growth opportunities, this segment is focused on balancing the oil and natural gas commodity mix to maximize profitability with its goal to add value by increasing both reserves and production over the long term so as to generate competitive returns on investment. 32 -------------------------------------------------------------------------------- Challenges Volatility in natural gas and oil prices; timely receipt of necessary permits and approvals; environmental and regulatory requirements; recruitment and retention of a skilled workforce; availability of drilling rigs, materials, auxiliary equipment and industry-related field services; inflationary pressure on development and operating costs; and competition from other exploration and production companies are ongoing challenges for this segment. Construction Materials and Contracting Strategy Focus on high-growth strategic markets located near major transportation corridors and desirable mid-sized metropolitan areas; strengthen long-term, strategic aggregate reserve position through purchase and/or lease opportunities; enhance profitability through cost containment, margin discipline and vertical integration of the segment's operations; develop and recruit talented employees; and continue growth through organic and acquisition opportunities. Vertical integration allows the segment to manage operations from aggregate mining to final lay-down of concrete and asphalt, with control of and access to permitted aggregate reserves being significant. A key element of the Company's long-term strategy for this business is to further expand its market presence in the higher-margin materials business (rock, sand, gravel, liquid asphalt, asphalt concrete, ready-mixed concrete and related products), complementing and expanding on the Company's expertise. Challenges Recruitment and retention of key personnel and volatility in the cost of raw materials such as diesel, gasoline, liquid asphalt, cement and steel, continue to be a concern. This business unit expects to continue cost containment efforts, positioning its operations for the resurgence in the private market, while continuing the emphasis on industrial, energy and public works projects. Construction Services Strategy Provide a superior return on investment by: building new and strengthening existing customer relationships; effectively controlling costs; retaining, developing and recruiting talented employees; and focusing our efforts on projects that will permit higher margins while properly managing risk. Challenges This segment operates in highly competitive markets with many jobs subject to competitive bidding. Maintenance of effective operational and cost controls, retention of key personnel, managing through downturns in the economy and effective management of working capital are ongoing challenges. For more information on the risks and challenges the Company faces as it pursues its growth strategies and other factors that should be considered for a better understanding of the Company's financial condition, see Item 1A - Risk Factors, as well as Part I, Item 1A - Risk Factors in the 2013 Annual Report. For more information on each segment's key growth strategies, projections and certain assumptions, see Prospective Information. For information pertinent to various commitments and contingencies, see Notes to Consolidated Financial Statements. 33 -------------------------------------------------------------------------------- Earnings Overview The following table summarizes the contribution to consolidated earnings by each of the Company's businesses. Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 (Dollars in millions, where applicable) Electric $ 7.8$ 4.4$ 18.9$ 14.2 Natural gas distribution (4.5 ) (5.9 ) 22.8 26.6 Pipeline and energy services 5.8 (6.4 ) 10.1 (4.1 ) Exploration and production 19.2 33.0 40.1 53.3 Construction materials and contracting 10.6 10.0 (13.0 ) (10.5 ) Construction services 14.3 12.9 30.9 24.6 Other 1.1 .5 1.3 .9 Intersegment eliminations (.9 ) (2.1 ) (1.2 ) (2.1 ) Earnings before discontinued operations 53.4 46.4 109.9 102.9 Income (loss) from discontinued operations, net of tax .5 (.1 ) .5 (.2 ) Earnings on common stock $ 53.9$ 46.3$ 110.4$ 102.7 Earnings per common share - basic: Earnings before discontinued operations $ .28$ .25$ .58$ .54 Discontinued operations, net of tax - - - -



Earnings per common share - basic $ .28$ .25 $

.58 $ .54 Earnings per common share - diluted: Earnings before discontinued operations $ .28$ .24$ .58$ .54 Discontinued operations, net of tax - - - -



Earnings per common share - diluted $ .28$ .24 $

.58 $ .54

Three Months Ended June 30, 2014 and 2013 Consolidated earnings for the quarter ended June 30, 2014, increased $7.6 million (16 percent) from the comparable prior period largely due to:



The absence of the 2013 natural gas gathering asset impairment of $9.0

million (after tax) and higher earnings from the Company's interest in the

Pronghorn oil and natural gas gathering and processing assets at the

pipeline and energy services business

Higher retail sales margins at the electric business

Partially offsetting these increases were an unrealized loss on commodity derivatives of $3.3 million (after tax) in 2014 compared to an unrealized gain on commodity derivatives of $8.2 million (after tax) in 2013, a loss of $7.3 million (after tax) resulting from a realized commodity derivative loss in 2014 compared to a realized commodity derivative gain in 2013 and higher depreciation, depletion and amortization expense; partially offset by increased oil production of 14 percent and increased average realized oil prices of 6 percent, excluding gain/loss on commodity derivatives, at the exploration and production business.



Six Months Ended June 30, 2014 and 2013 Consolidated earnings for the six months ended June 30, 2014, increased $7.7 million (8 percent) from the comparable prior period largely due to:

The absence of the 2013 natural gas gathering asset impairment of $9.0

million (after tax), as well as higher earnings from the Company's

interest in the Pronghorn oil and natural gas gathering and processing

assets at the pipeline and energy services business

Higher workloads and margins in the Western region at the construction

services business Partially offsetting these increases were a loss of $14.3 million (after tax) resulting from a realized commodity derivative loss in 2014 compared to a realized commodity derivative gain in 2013, an unrealized loss on commodity derivatives of $7.5 million (after tax) in 2014 compared to an unrealized gain on commodity derivatives of $4.6 million (after tax) in 2013, higher depreciation, depletion and amortization expense, as well as decreased natural gas production of 19 percent; partially offset by higher oil production of 14 percent and higher average realized natural gas prices of 52 percent, excluding gain/loss on commodity derivatives, at the exploration and production business. 34

-------------------------------------------------------------------------------- FINANCIAL AND OPERATING DATA Below are key financial and operating data for each of the Company's businesses. Electric Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 (Dollars in millions, where applicable) Operating revenues $ 65.1$ 57.0$ 138.8$ 121.6 Operating expenses: Fuel and purchased power 21.1 18.2 47.6 39.8 Operation and maintenance 20.5 20.5 38.9 36.8 Depreciation, depletion and amortization 8.5 7.9 17.1 16.5 Taxes, other than income 2.8 2.8 5.7 5.7 52.9 49.4 109.3 98.8 Operating income 12.2 7.6 29.5 22.8 Earnings $ 7.8$ 4.4$ 18.9$ 14.2 Retail sales (million kWh) 721.5 691.5 1,650.4 1,534.1 Average cost of fuel and purchased power per kWh $ .027$ .024$ .027$ .024



Three Months Ended June 30, 2014 and 2013 Electric earnings increased $3.4 million (77 percent) due to:

Higher retail sales margins, the result of higher rates, primarily due to

the recovery of costs of environmental upgrades; as well as increased

sales volumes of 4 percent, primarily to commercial and industrial customers



Higher other income, which includes $800,000 (after tax) largely related

to allowance for funds used during construction

Partially offsetting these increases were higher depreciation, depletion and amortization expense of $400,000 (after tax), primarily related to increased property, plant and equipment balances.



Six Months Ended June 30, 2014 and 2013 Electric earnings increased $4.7 million (32 percent) due to:

Higher retail sales margins, the result of higher rates, primarily due to

the recovery of costs of environmental upgrades; and increased sales volumes of 8 percent to all customer classes



Higher other income, which includes $1.2 million (after tax) largely

related to allowance for funds used during construction

Partially offsetting these increases were higher operation and maintenance expense, which includes $1.4 million (after tax) primarily related to higher benefit-related costs and contract services, along with higher depreciation, depletion and amortization expense of $400,000 (after tax), as previously discussed. 35 --------------------------------------------------------------------------------

Natural Gas Distribution Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 (Dollars in millions, where applicable) Operating revenues $ 146.1$ 127.6$ 520.3$ 459.3 Operating expenses: Purchased natural gas sold 89.1 73.5 346.4 286.9 Operation and maintenance 35.9 35.7 73.8 69.9 Depreciation, depletion and amortization 13.5 12.4 26.8 24.5 Taxes, other than income 9.9 9.5 27.8 25.7 148.4 131.1 474.8 407.0 Operating income (loss) (2.3 ) (3.5 ) 45.5 52.3 Earnings (loss) $ (4.5 )$ (5.9 )$ 22.8$ 26.6 Volumes (MMdk): Sales 14.7 15.3 60.0 60.2 Transportation 29.9 30.3 69.2 68.5 Total throughput 44.6 45.6 129.2 128.7 Degree days (% of normal)* Montana-Dakota/Great Plains 109 % 130 % 107 % 104 % Cascade 78 % 82 % 93 % 93 % Intermountain 95 % 99 % 96 % 110 % Average cost of natural gas, including transportation, per dk $ 6.05$ 4.82 $



5.77 $ 4.77

* Degree days are a measure of the daily temperature-related demand for energy for heating.

Three Months Ended June 30, 2014 and 2013 The natural gas distribution business experienced a seasonal loss of $4.5 million compared to a seasonal loss of $5.9 million a year ago (a 24 percent improvement). The improvement was largely due to:



Higher sales margins, including approved rate increases effective in late

2013, offset in part by lower volumes, primarily due to warmer weather

Lower regulated operation and maintenance expense, which includes $500,000

(after tax) largely related to decreased benefit-related costs and other expenses, offset in part by increased contract services



Higher other income, which includes $500,000 (after tax) largely related

to allowance for funds used during construction

Partially offsetting these increases were higher depreciation, depletion and amortization expense of $700,000 (after tax), primarily resulting from higher property, plant and equipment balances.



The previous table also reflects higher revenue and higher operation and maintenance expense related to nonregulated activity.

Six Months Ended June 30, 2014 and 2013 Natural gas distribution earnings decreased $3.8 million (14 percent) due to:

The absence in 2014 of the $2.8 million (after tax) gain on the sale of

Montana-Dakota's nonregulated appliance service and repair business in March 2013



Higher operation and maintenance expense, which includes $2.7 million

(after tax) largely related to higher payroll and benefit-related costs and higher contract services



Higher depreciation, depletion and amortization expense of $1.4 million

(after tax), as previously discussed

Partially offsetting these decreases were higher retail sales margins, largely resulting from approved rate increases effective in late 2013; as well as higher other income, which includes $800,000 (after tax) largely related to allowance for funds used during construction. 36 --------------------------------------------------------------------------------



Pipeline and Energy Services

Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 (Dollars in millions) Operating revenues $ 51.4$ 50.9$ 113.3$ 97.3 Operating expenses: Purchased natural gas sold 13.0 15.8 39.2 28.6 Operation and maintenance 16.9 32.1 * 33.6 49.3 * Depreciation, depletion and amortization 7.2 7.7 14.3 14.9 Taxes, other than income 3.4 3.5 6.6 6.9 40.5 59.1 93.7 99.7 Operating income (loss) 10.9 (8.2 ) 19.6 (2.4 ) Earnings (loss) $ 5.8 $ (6.4 ) * $ 10.1$ (4.1 ) * Transportation volumes (MMdk) 53.3 40.3 105.8 77.1 Natural gas gathering volumes (MMdk) 9.7 10.0 19.1 19.9 Customer natural gas storage balance (MMdk): Beginning of period 10.4 24.7 26.7 43.7 Net injection (withdrawal) 1.0 .5 (15.3 ) (18.5 ) End of period 11.4 25.2 11.4 25.2 * Reflects an impairment of coalbed natural gas gathering assets of $14.5 million ($9.0 million after tax).



Three Months Ended June 30, 2014 and 2013 Pipeline and energy services recognized earnings of $5.8 million compared to a loss of $6.4 million for the comparable prior period due to:

Absence of the 2013 natural gas gathering asset impairment of $9.0 million

(after tax) Higher earnings from the Company's interest in the Pronghorn oil and natural gas gathering and processing assets, primarily due to higher volumes Higher earnings of $1.2 million (after tax) due to increased transportation rates



Lower operation and maintenance expense (excluding the asset impairment

and Pronghorn-related expense), which includes $800,000 (after tax) largely related to lower legal-related costs



These increases were partially offset by lower storage services revenue of $700,000 (after tax), largely due to lower average storage balances and lower rates.

Six Months Ended June 30, 2014 and 2013 Pipeline and energy services recognized earnings of $10.1 million compared to a loss of $4.1 million for the comparable prior period due to:



Absence of the 2013 natural gas gathering asset impairment of $9.0 million

(after tax) Higher earnings from the Company's interest in the Pronghorn oil and natural gas gathering and processing assets, primarily due to higher volumes and prices Higher earnings of $2.0 million (after tax) due to increased transportation rates and volumes



Lower operation and maintenance expense (excluding the asset impairment

and Pronghorn-related expense), which includes $1.1 million (after tax)

largely related to lower legal-related costs

These increases were partially offset by lower storage services revenue of $1.3 million (after tax), largely due to lower average storage balances.

Results also reflect higher operating revenues and higher purchased natural gas sold, both related to higher natural gas prices.

37 --------------------------------------------------------------------------------

Exploration and Production Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 (Dollars in millions, where applicable) Operating revenues: Oil $ 127.2$ 105.9$ 240.8$ 205.9 NGL 6.3 6.2 13.2 13.7 Natural gas 21.6 23.2 52.1 42.4 Realized gain (loss) on commodity derivatives (10.3 ) 1.3 (17.1 ) 5.6 Unrealized gain (loss) on commodity derivatives (5.2 ) 13.0 (11.9 ) 7.2 139.6 149.6 277.1 274.8 Operating expenses: Operation and maintenance: Lease operating costs 23.9 22.0 48.0 42.8 Gathering and transportation 3.1 4.2 5.4 8.5 Other 11.8 10.3 23.7 20.4 Depreciation, depletion and amortization 52.9 45.1 102.4 88.3 Taxes, other than income: Production and property taxes 14.2 12.3 27.1 23.9 Other .2 .3 .6 .6 106.1 94.2 207.2 184.5 Operating income 33.5 55.4 69.9 90.3 Earnings $ 19.2$ 33.0$ 40.1$ 53.3 Production: Oil (MBbls) 1,366 1,201 2,646 2,319 NGL (MBbls) 167 191 331 392 Natural gas (MMcf) 5,756 6,987 11,034 13,700 Total production (MBOE) 2,492 2,557 4,816 4,995 Average realized prices (excluding realized and unrealized gain/loss on commodity derivatives): Oil (per Bbl) $ 93.06$ 88.12$ 90.99$ 88.75 NGL (per Bbl) $ 37.67$ 32.26$ 39.94$ 34.86 Natural gas (per Mcf) $ 3.76$ 3.33$ 4.72$ 3.10 Average realized prices (including realized gain/loss on commodity derivatives): Oil (per Bbl) $ 87.03$ 90.55$ 86.43$ 91.18 NGL (per Bbl) $ 37.67$ 32.26$ 39.94$ 34.86 Natural gas (per Mcf) $ 3.40$ 3.09$ 4.27$ 3.09 Average depreciation, depletion and $ 20.45$ 16.90$ 20.45$ 16.90 amortization rate, per BOE Production costs, including taxes, per BOE: Lease operating costs $ 9.57$ 8.59$ 9.97$ 8.57 Gathering and transportation 1.24 1.66 1.13 1.71 Production and property taxes 5.68 4.81 5.63 4.78 $ 16.49$ 15.06$ 16.73$ 15.06 38

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Three Months Ended June 30, 2014 and 2013 Exploration and production earnings decreased $13.8 million (42 percent) due to:

Unrealized loss on commodity derivatives of $3.3 million (after tax) in

2014 compared to an unrealized gain on commodity derivatives of $8.2 million (after tax) in 2013



A loss of $7.3 million (after tax) resulting from a realized commodity

derivative loss in 2014 compared to a realized commodity derivative gain in 2013



Higher depreciation, depletion and amortization expense of $4.9 million

(after tax), largely related to higher depletion rates

Decreased natural gas production of 18 percent, largely due to the sale of

non-strategic assets



Partially offsetting these decreases were:

Increased oil production of 14 percent, primarily related to the Powder

River Basin acquisition

Increased average realized oil prices of 6 percent, excluding gain/loss on

commodity derivatives



Six Months Ended June 30, 2014 and 2013 Exploration and production earnings decreased $13.2 million (25 percent) due to:

A loss of $14.3 million (after tax) resulting from a realized commodity

derivative loss in 2014 compared to a realized commodity derivative gain in 2013



Unrealized loss on commodity derivatives of $7.5 million (after tax) in

2014 compared to an unrealized gain on commodity derivatives of $4.6 million (after tax) in 2013



Higher depreciation, depletion and amortization expense of $8.9 million

(after tax), primarily related to higher depletion rates

Decreased natural gas production of 19 percent, largely due to the sale of

non-strategic assets

Higher lease operating expenses of $3.3 million (after tax), primarily in

the Paradox Basin and Bakken areas Higher general and administrative expenses of $2.0 million (after tax), primarily related to higher professional services and higher payroll-related costs



Partially offsetting these decreases were:

Increased oil production of 14 percent, primarily related to drilling

activity in the Paradox Basin and the Powder River Basin acquisition

Higher average realized natural gas prices of 52 percent, excluding

gain/loss on commodity derivatives

Higher average realized oil prices of 3 percent, excluding gain/loss on

commodity derivatives



Construction Materials and Contracting

Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 (Dollars in millions) Operating revenues $ 442.6$ 431.3$ 611.0$ 597.6 Operating expenses: Operation and maintenance 393.4 381.2 569.1 547.9 Depreciation, depletion and amortization 17.4 18.7 35.0 37.7 Taxes, other than income 10.6 10.6 18.9 19.1 421.4 410.5 623.0 604.7 Operating income (loss) 21.2 20.8 (12.0 ) (7.1 ) Earnings (loss) $ 10.6$ 10.0$ (13.0 )$ (10.5 ) Sales (000's): Aggregates (tons) 6,971 6,152 9,800 9,110 Asphalt (tons) 1,474 1,518 1,658 1,667 Ready-mixed concrete (cubic yards) 907 846



1,404 1,326

Three Months Ended June 30, 2014 and 2013 Construction materials and contracting earnings increased $600,000 (5 percent) due to higher earnings of $2.0 million (after tax) resulting from higher aggregate margins and volumes, partially offset by lower earnings resulting from lower construction margins. 39 -------------------------------------------------------------------------------- Six Months Ended June 30, 2014 and 2013 Construction materials and contracting experienced a loss of $13.0 million compared to a loss of $10.5 million a year ago (a 23 percent decline). The decline was the result of: Lower earnings of $4.7 million (after tax) resulting from lower construction revenues and margins



Higher selling, general and administrative expenses of $1.8 million (after

tax), including higher labor and insurance costs

Partially offsetting the decline were:

Higher earnings of $2.3 million (after tax) resulting from higher

aggregate margins

Higher earnings resulting from higher other product line margins

Higher earnings of $600,000 (after tax) resulting from higher asphalt margins Construction Services Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 (In millions) Operating revenues $ 282.3$ 279.6$ 556.0$ 511.0 Operating expenses: Operation and maintenance 246.5 245.9 480.6 444.3 Depreciation, depletion and amortization 3.2 3.0 6.4 6.0 Taxes, other than income 8.3 8.4 18.5 18.0 258.0 257.3 505.5 468.3 Operating income 24.3 22.3 50.5 42.7 Earnings $ 14.3$ 12.9$ 30.9$ 24.6



Three Months Ended June 30, 2014 and 2013 Construction services earnings increased $1.4 million (11 percent) due to higher margins in the Central region, primarily related to outside work.

Six Months Ended June 30, 2014 and 2013 Construction services earnings increased $6.3 million (26 percent) due to:

Higher workloads and margins in the Western region and higher margins in

the Central region, both primarily related to outside work

Higher electrical supply sales and margins

Partially offsetting these increases were higher selling, general and administrative expense of $1.4 million (after tax), primarily related to higher payroll-related costs.

40 --------------------------------------------------------------------------------

Other Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 (In millions) Operating revenues $ 2.2$ 2.3$ 4.3$ 4.5 Operating expenses: Operation and maintenance 1.1 1.4 2.5 2.7 Depreciation, depletion and amortization .6 .5 1.1 1.0 Taxes, other than income - - - .1 1.7 1.9 3.6 3.8 Operating income .5 .4 .7 .7 Income from continuing operations 1.1 .5 1.3 .9 Income (loss) from discontinued operations, net of tax .5 (.1 ) .5 (.2 ) Earnings $ 1.6$ .4$ 1.8$ .7 Three Months Ended June 30, 2014 and 2013 Other earnings increased $1.2 million, including the effects of the vacation of an arbitration award which is included in discontinued operations as discussed in Note 21.



Six Months Ended June 30, 2014 and 2013 Other earnings increased $1.1 million, as previously discussed.

Intersegment Transactions Amounts presented in the preceding tables will not agree with the Consolidated Statements of Income due to the Company's elimination of intersegment transactions. The amounts relating to these items are as follows: Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 (In millions) Intersegment transactions: Operating revenues $ 35.3$ 37.7$ 83.9$ 73.9 Purchased natural gas sold 17.7 19.1 56.3 46.1 Operation and maintenance 16.0 15.2 25.3 24.4 Depreciation, depletion and amortization .2 - .4 - Earnings on common stock .9 2.1 1.2 2.1



For more information on intersegment eliminations, see Note 18.

PROSPECTIVE INFORMATION The following information highlights the key growth strategies, projections and certain assumptions for the Company and its subsidiaries and other matters for certain 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 in Part II, Item 1A - Risk Factors, as well as Part I, Item 1A - Risk Factors in the 2013 Annual Report. Changes in such assumptions and factors could cause actual future results to differ materially from the Company's growth and earnings projections.



MDU Resources Group, Inc. Adjusted earnings per common share for 2014, diluted, are projected in the

range of $1.50 to $1.65, excluding discontinued operations and the unrealized

loss of $7.5 million (after tax) on commodity derivatives. Including these

adjustments, GAAP earnings guidance for 2014 is in the same range. Unrealized

commodity derivatives fair values can fluctuate causing actual GAAP earnings

to vary accordingly. The Company believes that these non-GAAP financial measures are useful 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 41 -------------------------------------------------------------------------------- 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.



The Company's long-term compound annual growth goals on 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 gross capital expenditures for 2014 are approximately $1.1 billion.

The estimate excludes noncontrolling interest capital expenditures related to

Dakota Prairie Refining. Electric and natural gas distribution Rate base growth is projected to be approximately 9 percent compounded



annually over the next five years, including plans for an approximate $1.3

billion capital investment program.

Regulatory actions



The Company filed an application February 27, 2014, with the NDPSC

requesting approval for a generation resource recovery rider for $7.4

million to recover costs associated with the 88-MW simple-cycle natural gas

turbine and associated facilities currently under construction. The

estimated project cost is $77 million and the projected in-service date is

third quarter 2014. It is located adjacent to the Company's Heskett

Generating Station near Mandan, North Dakota. The capacity is necessary to

meet the requirements of the Company's integrated electric system customers

and will be a partial replacement for third-party contract capacity expiring

in 2015. On March 12, 2014, the NDPSC suspended the filing pending further

review and a hearing was held May 28, 2014. A work session was held July 18,

2014, to discuss the request. Advance determination of prudence and a

Certificate of Public Convenience and Necessity have been received from the

NDPSC. For more information, see Note 20.

The Company filed an application September 18, 2013, with the NDPSC for a

natural gas rate increase, as discussed in Note 20.

The Company submitted a request April 8, 2014, to the NDPSC to update an

environmental cost recovery rider related to costs resulting from the

environmental retrofit required to be installed at the Big Stone Station to

reflect actual costs incurred through February 2014 and projected costs

through June 2015. The NDPSC approved the rider July 10, 2014, for recovery

of $8.6 million annually. The Company's share of the cost for the

installation is approximately $90 million and is expected to be complete in

2015. The NDPSC had earlier approved advance determination of prudence for recovery of costs on the system. For more information, see Note 20.



Investments are being made in 2014 totaling approximately $80 million to serve

the growing electric and natural gas customer base associated with the Bakken

oil development where customer growth is substantially higher than the national average.



The Company is engaged in a 30-mile, approximately $60 million natural gas

line project into the Hanford Nuclear Site in Washington.

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 $170 million. The project is a MISO multi-value 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 in

North Dakota on July 10, 2014. A route permit hearing was held June 10, 2014,

in South Dakota. The project is expected to be complete in 2019.

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 served by 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 in the Pacific Northwest and

Idaho. 42

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Pipeline and energy services The Company, in conjunction with Calumet, formed Dakota Prairie Refining, to

develop, build and operate Dakota Prairie Refinery. Construction began on the

facility in late March 2013 and it is approximately 75 percent complete. When

complete, it will process Bakken crude into diesel, which will be marketed

within the Bakken region. Other by-products, naphtha and atmospheric tower

bottoms, will be railed to other areas. The total project cost estimate is

approximately $350 million, with a projected in-service date in late 2014.

EBITDA for the first year of operation is projected to be in the range of

$70 million to $90 million, to be shared equally with Calumet.

In January 2014, the Company launched an open season to obtain capacity

commitments on a proposed 375-mile natural gas pipeline from western North

Dakota to northwestern Minnesota to transport natural gas to markets in

eastern North Dakota, Minnesota, Wisconsin, Michigan and other Midwest

markets. The pipeline is expected to provide access to additional markets via

interconnections with pipelines owned by Great Lakes Gas Transmission, Viking

Gas Transmission and potentially TransCanada, in northwestern Minnesota. An

interconnection with the Alliance Pipeline system in eastern North Dakota also

is possible. Initially the pipeline would transport approximately 400 MMcf per

day of natural gas and could be expanded to more than 500 MMcf per day. The

project investment is estimated to be approximately $650 million. The open

season ended May 30, 2014, and the Company is evaluating the responses

received and working with those parties as well as other interested parties.

The Company expects to provide a status update on its efforts by this fall. If

the project moves forward, following the receipt of necessary permits and

regulatory approvals, construction on the new pipeline could begin in 2016

with completion expected in 2017.

On October 31, 2013, WBI Energy Transmission filed a Section 4 rate case with

the FERC, as discussed in Note 20.

The Company is engaged in various natural gas pipeline projects to be

constructed in 2014, including connections for the planned Garden Creek II

natural gas processing plant in the Bakken, an expansion of its transmission

system to increase capacity to the Black Hills, and a 24-mile pipeline and

related processing facilities to transport Fidelity's Paradox basin natural

gas production. The total cost for these projects is approximately $50 million.



The Company continues to pursue expansion of facilities and services offered

to customers. Energy development within its geographic region is expanding,

most notably in the Bakken area, where the Company owns an extensive natural

gas pipeline system. Ongoing energy development is expected to continue to

provide growth opportunities for this business.

Exploration and production The Company expects to spend approximately $620 million in gross capital

expenditures in 2014, which is likely to be partially offset by the expected

sale of certain Mountrail County, North Dakota assets and other planned asset

sales this year.

For 2014, the Company now expects a 10 to 15 percent increase in oil

production, lower than its earlier estimate primarily the result of the

expected sale of certain Mountrail County assets. NGL production is expected

to decline 20 to 25 percent and natural gas production is expected to be

20 to 25 percent lower compared to a year ago. The declines are primarily the

result of the divestment of certain non-strategic natural gas-based properties

in 2013 and the expected divestment of the Company's South Texas assets this

year. The vast majority of the capital program is focused on growing oil production.



The Company has a total of three operated drilling rigs deployed on its

acreage with two deployed in the Bakken area and one in the Paradox area.

There are two non-operated rigs deployed on the Company's Powder River Basin

acreage. Bakken areas



The Company owns a total of approximately 108,500 net acres of leaseholds in

Mountrail and Stark counties, North Dakota and Richland County, Montana,

assuming the divestment of 4,363 net acres in Mountrail County. The Middle

Bakken and Three Forks formations are targeted in North Dakota and the Red River formation is targeted in Montana.



Capital expenditures are expected to total approximately $125 million in

2014, excluding the proceeds from the pending sale of Mountrail County acreage.



Net oil production for the second quarter was approximately 7,600 BOPD.

The Company has been testing two alternative completion techniques; plug and

perforation and coil tubing with cemented liners. The coil tubing with

cemented liner technique is encouraging and focus is on optimizing this

approach. 43

--------------------------------------------------------------------------------



Paradox Basin, Utah

The Company owns approximately 140,000 net acres of leaseholds, including

its acquisitions of 35,000 net acres of leaseholds in February 2014, and

11,000 net acres of leaseholds in April 2014 and has an option to earn another 20,000 acres.



Capital expenditures are expected to total approximately $150 million in 2014.

Well costs range from $8 million to $11 million per well depending upon

lateral lengths. Estimated ultimate recoveries are increasing with the upper

range now at 1.7 MMBbls of oil per well.



The Cane Creek Unit 12-1 well has cumulative production of 740 MBbls of oil

since it began producing in September 2012. Artificial lift facilities have

recently been installed.

Net oil production for second quarter was approximately 3,290 BOPD, up

42 percent from second quarter 2013 and down 8 percent from first quarter

2014. Operational issues/downtime on several high-rate wells occurred during

the quarter, which have now been broadly resolved with the installation of

artificial lift. Drilling on multi-well pads, which defers completion, and

two low-rate fringe acreage tests have delayed production growth. Higher

growth is expected in third quarter 2014. The second drilling rig will return when sufficient permits are in place to sustain two rigs. The Company's understanding of this play continues to improve. It is



anticipated that this field will play a key role in the Company's oil growth

strategy.



Powder River Basin, Wyoming

In March 2014, the Company acquired 24,500 net acres of leaseholds in

Converse County, Wyoming.

Capital expenditures are expected to total approximately $260 million in

2014, including the acquisition costs, related closing adjustments and drilling capital.



Net production for the second quarter 2014 was 2,000 BOE per day (75 percent

oil), up 23 percent from late March 2014 average net production of 1,630 BOE

per day.



Earnings guidance reflects estimated average NYMEX index prices for August

through December 2014 in the range of $96 to $102 per Bbl of crude oil, and

$4.00 to $5.00 per Mcf of natural gas. Estimated prices for NGL are in the

range of $37 to $40 per Bbl.

Derivatives:



For July through December 2014, 12,000 BOPD at a weighted average price of

$96.47.



For July through December 2014, 40,000 MMBtu of natural gas per day at a

weighted average price of $4.10.

For January through March 2015, 3,000 BOPD at a weighted average price of

$98.00.



For 2015, 10,000 MMBtu of natural gas per day at a weighted average price of

$4.28.



The commodity derivative instruments that are in place as of August 1, 2014,

are summarized in the following chart: 44

-------------------------------------------------------------------------------- Period Forward Notional Volume Price



Commodity Type Index Outstanding (Bbl/MMBtu) (Per Bbl/MMBtu)

Crude Oil Swap NYMEX 7/14 - 12/14 184,000 $94.05 Crude Oil Swap NYMEX 7/14 - 12/14 184,000 $95.00 Crude Oil Swap NYMEX 7/14 - 9/14 184,000 $95.75 Crude Oil Swap NYMEX 7/14 - 9/14 184,000 $96.00 Crude Oil Swap NYMEX 7/14 - 9/14 92,000 $96.25 Crude Oil Swap NYMEX 7/14 - 12/14 184,000 $94.25 Crude Oil Swap NYMEX 7/14 - 12/14 184,000 $95.00 Crude Oil Swap NYMEX 7/14 - 12/14 184,000 $95.25 Crude Oil Swap NYMEX 7/14 - 12/14 368,000 $96.00 Crude Oil Swap NYMEX 10/14 - 12/14 276,000 $100.50 Crude Oil Swap NYMEX 10/14 - 12/14 184,000 $101.50 Crude Oil Swap NYMEX 1/15 - 3/15 270,000 $98.00 Natural Gas Swap NYMEX 7/14 - 12/14 3,680,000 $4.13 Natural Gas Swap NYMEX 7/14 - 12/14 1,840,000 $4.05 Natural Gas Swap NYMEX 7/14 - 12/14 1,840,000 $4.10 Natural Gas Swap NYMEX 1/15 - 12/15 3,650,000 $4.28



Construction materials and contracting Approximate work backlog as of June 30, 2014, was $764 million, compared to

$730 million a year ago. Private work represents 11 percent of construction

backlog and public work represents 89 percent of backlog. The backlog includes

a variety of projects such as highway grading, paving and underground

projects, airports, bridge work and subdivisions.

The Company's approximate backlog in North Dakota as of June 30, 2014, was

$158 million. North Dakota backlog was $165 million a year ago.

Projected revenues included in the Company's 2014 earnings guidance are in the

range of $1.6 billion to $1.8 billion.

The Company anticipates margins in 2014 to be in line with 2013 margins.

The Company continues to pursue opportunities for expansion in energy projects

such as refineries, transmission, 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.



Of the seven labor contracts that Knife River was negotiating, as reported in

Items 1 and 2 - Business and Properties - General in the 2013 Annual Report,

six have been ratified. The one remaining contract is still in negotiation.

Construction services Approximate work backlog as of June 30, 2014, was $386 million, compared to

$447 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.

The Company's approximate backlog in North Dakota as of June 30, 2014, was

$11 million. The construction services business did not have any backlog in

North Dakota a year ago.

Projected revenues included in the Company's 2014 earnings guidance are in

the range of $1.1 billion to $1.2 billion.

The Company anticipates margins in 2014 to be in line with 2013 margins.

45 --------------------------------------------------------------------------------



The Company continues to pursue opportunities for expansion in energy

projects such as refineries, transmission, substations, utility services, as

well as solar. Initiatives are aimed at capturing additional market share and

expanding into new markets.

NEW ACCOUNTING STANDARDS For information regarding new accounting standards, see Note 8, which is incorporated by reference.

CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES The Company's critical accounting policies involving significant estimates include impairment testing of oil and natural gas properties, impairment testing of long-lived assets and intangibles, revenue recognition, pension and other postretirement benefits, and income taxes. There were no material changes in the Company's critical accounting policies involving significant estimates from those reported in the 2013 Annual Report. For more information on critical accounting policies involving significant estimates, see Part II, Item 7 in the 2013 Annual Report. LIQUIDITY AND CAPITAL COMMITMENTS At June 30, 2014, the Company had cash and cash equivalents of $90.3 million and available capacity of $669.8 million under the outstanding credit facilities of the Company and its subsidiaries. The Company expects to meet its obligations for debt maturing within one year from various sources, including internally generated funds; the Company's credit facilities, as described later; and through the issuance of long-term debt and the Company's equity securities.



Cash flows Operating activities The changes in cash flows from operating activities generally follow the results of operations as discussed in Financial and Operating Data and also are affected by changes in working capital.

Cash flows provided by operating activities in the first six months of 2014 decreased $23.4 million from the comparable period in 2013 primarily due to higher income taxes paid.

Investing activities Cash flows used in investing activities in the first six months of 2014 increased $175.2 million from the comparable period in 2013. The increase in cash flows used in investing activities was primarily due to higher acquisition-related capital expenditures at the exploration and production business; offset in part by lower ongoing capital expenditures at the exploration and production business. Financing activities Cash flows provided by financing activities in the first six months of 2014 increased $177.5 million from the comparable period in 2013. The increase in cash flows provided by financing activities was primarily due to the issuance of $132.3 million of common stock; as well as lower repayment of long-term debt of $102.9 million. Partially offsetting this increase were higher dividends paid in 2014 compared to 2013 due to the acceleration of the first quarter 2013 quarterly common stock dividend to 2012. Defined benefit pension plans There were no material changes to the Company's qualified noncontributory defined benefit pension plans from those reported in the 2013 Annual Report. For more information, see Note 19 and Part II, Item 7 in the 2013 Annual Report. Capital expenditures Net capital expenditures for the first six months of 2014 were $579.2 million and are estimated to be approximately $863 million for 2014. Estimated capital expenditures include: System upgrades Routine replacements Service extensions



Routine equipment maintenance and replacements

Buildings, land and building improvements

Pipeline, gathering and other midstream projects

Further development of existing properties, acquisition of additional

leasehold acreage, exploratory drilling and proceeds from the sale of certain assets at the exploration and production segment Power generation and transmission opportunities, including certain costs for additional electric generating capacity



Environmental upgrades

The Company's proportionate share of Dakota Prairie Refinery at the pipeline and energy services segment



Other growth opportunities

46 -------------------------------------------------------------------------------- The Company continues to evaluate potential future acquisitions and other growth opportunities; however, they are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary significantly from the estimated 2014 capital expenditures referred to previously. The Company expects the 2014 estimated capital expenditures to be funded by various sources, including internally generated funds; the Company's credit facilities, as described later; and through the issuance of long-term debt and the Company's equity securities. Capital resources Certain debt instruments of the Company and its subsidiaries, including those discussed later, contain restrictive covenants and cross-default provisions. In order to borrow under the respective credit agreements, the Company and its subsidiaries must be in compliance with the applicable covenants and certain other conditions, all of which the Company and its subsidiaries, as applicable, were in compliance with at June 30, 2014. In the event the Company and its subsidiaries do not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued. For more information on the covenants, certain other conditions and cross-default provisions, see Note 16 and Part II, Item 8 - Note 9, in the 2013 Annual Report.



The following table summarizes the outstanding revolving credit facilities of the Company and its subsidiaries at June 30, 2014:

Company Facility Facility Limit Amount Outstanding Letters of Credit Expiration Date (In millions) Commercial paper/ Revolving MDU Resources credit Group, Inc. agreement (a) $ 175.0 $ 79.0 (b) $ - 5/8/19 Cascade Revolving Natural Gas credit Corporation agreement $ 50.0 (c) $ - $ 2.2 (d) 7/9/18 Revolving Intermountain credit Gas Company agreement $ 65.0 (e) $ - $ - 7/13/18 Commercial paper/ Centennial Revolving Energy credit Holdings, Inc. agreement (f) $ 650.0 $ 189.0 (b) $ - 5/8/19 (a) The commercial paper program is supported by a revolving credit agreement with various banks (provisions allow for increased borrowings, at the option of the Company on stated conditions, up to a maximum of $225.0 million). There were no amounts outstanding under the credit agreement. (b) Amount outstanding under commercial paper program. (c) Certain provisions allow for increased borrowings, up to a maximum of $75.0 million. (d) The outstanding letter of credit, as discussed in Note 21, reduces the amount available under the credit agreement. (e) Certain provisions allow for increased borrowings, up to a maximum of $90.0 million. (f) The commercial paper program is supported by a revolving credit agreement with various banks (provisions allow for increased borrowings, at the option of Centennial on stated conditions, up to a maximum of $800.0 million). There were no amounts outstanding under the credit agreement. -------------------------------------------------------------------------------- The Company's and Centennial's respective commercial paper programs are supported by revolving credit agreements. While the amount of commercial paper outstanding does not reduce available capacity under the respective revolving credit agreements, the Company and Centennial do not issue commercial paper in an aggregate amount exceeding the available capacity under their credit agreements. The commercial paper borrowings may vary during the period, largely the result of fluctuations in working capital requirements due to the seasonality of the construction businesses.



The following includes information related to the preceding table.

MDU Resources Group, Inc. On May 8, 2014, the Company amended the revolving credit agreement to increase the borrowing limit to $175.0 million and extend the termination date to May 8, 2019. The Company's revolving credit agreement supports its commercial paper program. Commercial paper borrowings under this agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper borrowings. The Company's objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. Downgrades in the Company's credit ratings have not limited, nor are currently expected to limit, the Company's ability 47 -------------------------------------------------------------------------------- to access the capital markets. If the Company were to experience a downgrade of its credit ratings, it may need to borrow under its credit agreement and may experience an increase in overall interest rates with respect to its cost of borrowings. Prior to the maturity of the credit agreement, the Company expects that it will negotiate the extension or replacement of this agreement. If the Company is unable to successfully negotiate an extension of, or replacement for, the credit agreement, or if the fees on this facility become too expensive, which the Company does not currently anticipate, the Company would seek alternative funding. The Company's coverage of fixed charges including preferred stock dividends was 4.8 times for the 12 months ended June 30, 2014 and December 31, 2013. Due to the $246.8 million after-tax noncash write-downs of oil and natural gas properties in 2012, earnings were insufficient by $19.8 million to cover fixed charges for the 12 months ended June 30, 2013. If the $246.8 million after-tax noncash write-downs were excluded, the coverage of fixed charges including preferred stock dividends would have been 4.5 times for the 12 months ended June 30, 2013. The coverage of fixed charges including preferred stock dividends, that excludes the effect of the after-tax noncash write-downs of oil and natural gas properties is a non-GAAP financial measure. The Company believes that this non-GAAP financial measure is useful because the write-downs excluded are not indicative of the Company's cash flows available to meets its fixed charges obligations. The presentation of this additional information is not meant to be considered a substitute for the financial measure prepared in accordance with GAAP. Total equity as a percent of total capitalization was 58 percent, 57 percent and 60 percent at June 30, 2014 and 2013 and December 31, 2013, respectively. This ratio is calculated as the Company's total equity, divided by the Company's total capital. Total capital is the Company's total debt, including short-term borrowings and long-term debt due within one year, plus total equity. This ratio indicates how a company is financing its operations, as well as its financial strength. On May 20, 2013, the Company entered into an Equity Distribution Agreement with Wells Fargo Securities, LLC with respect to the issuance and sale of up to 7.5 million shares of the Company's common stock. The common stock may be offered for sale, from time to time, in accordance with the terms and conditions of the agreement. Sales of such common stock may not be made after February 28, 2016. Proceeds from the shares of common stock under the agreement have been and are expected to be used for corporate development purposes and other general corporate purposes. Under the Equity Distribution Agreement, the Company issued 2.2 million shares of stock between April 1, 2014 and June 30, 2014, receiving net proceeds of $72.3 million, 3.7 million shares of stock between January 1, 2014 and June 30, 2014, receiving net proceeds of $122.4 million and a total of 4.2 million shares of stock as of June 30, 2014, receiving net proceeds of $137.0 million. The Company currently has a shelf registration statement on file with the SEC, under which the Company may issue and sell any combination of common stock and debt securities. The Company may sell all or a portion of such securities if warranted by market conditions and the Company's capital requirements. Any public offer and sale of such securities will be made only by means of a prospectus meeting the requirements of the Securities Act and the rules and regulations thereunder. The Company's board of directors currently has authorized the issuance and sale of up to an aggregate of $1.0 billion worth of such securities. The Company's board of directors reviews this authorization on a periodic basis and the aggregate amount of securities authorized may be increased in the future. The Company entered into a $150.0 million note purchase agreement on January 28, 2014. On April 15, 2014, the Company issued $50.0 million of Senior Notes with a due date of April 15, 2044, at an interest rate of 5.2 percent. The remaining $100.0 million of Senior Notes was issued on July 15, 2014, with due dates ranging from July 15, 2024 to July 15, 2026, at a weighted average interest rate of 4.3 percent. Centennial Energy Holdings, Inc. On May 8, 2014, Centennial entered into an amended and restated revolving credit agreement which increased the borrowing limit to $650.0 million and extended the termination date to May 8, 2019. The credit agreement contains customary covenants and provisions, including a covenant of Centennial not to permit, as of the end of any fiscal quarter, the ratio of total consolidated debt to total consolidated capitalization to be greater than 65 percent. Other covenants include restrictions on the sale of certain assets, limitations on subsidiary indebtedness and the making of certain loans and investments. Centennial's revolving credit agreement contains cross-default provisions. These provisions state that if Centennial or any subsidiary of Centennial fails to make any payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, the agreement will be in default. 48 -------------------------------------------------------------------------------- Centennial's revolving credit agreement supports its commercial paper program. Commercial paper borrowings under this agreement are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper borrowings. Centennial's objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. Downgrades in Centennial's credit ratings have not limited, nor are currently expected to limit, Centennial's ability to access the capital markets. If Centennial were to experience a downgrade of its credit ratings, it may need to borrow under its credit agreement and may experience an increase in overall interest rates with respect to its cost of borrowings. Prior to the maturity of the Centennial credit agreement, Centennial expects that it will negotiate the extension or replacement of this agreement, which provides credit support to access the capital markets. In the event Centennial is unable to successfully negotiate this agreement, or in the event the fees on this facility become too expensive, which Centennial does not currently anticipate, it would seek alternative funding. Centennial entered into two separate two year $125.0 million term loan agreements with variable interest rates on March 31, 2014 and April 2, 2014, respectively. These agreements contain customary covenants and default provisions, including covenants not to permit, as of the end of any fiscal quarter, the ratio of Centennial's total debt to total capitalization to be greater than 65 percent. The covenants also include certain limitations on subsidiary indebtedness and restrictions on the sale of certain assets and on the making of certain loans and investments.



WBI Energy Transmission, Inc.WBI Energy Transmission has a $175.0 million amended and restated uncommitted long-term private shelf agreement with an expiration date of September 12, 2016. WBI Energy Transmission had $100.0 million of notes outstanding at June 30, 2014, which reduced capacity under this uncommitted private shelf agreement.

Off balance sheet arrangements In connection with the sale of the Brazilian Transmission Lines, Centennial has agreed to guarantee payment of any indemnity obligations of certain of the Company's indirect wholly owned subsidiaries who are the sellers in three purchase and sale agreements for periods ranging up to 10 years from the date of sale. The guarantees were required by the buyers as a condition to the sale of the Brazilian Transmission Lines. For more information, see Note 12.



Centennial continues to guarantee CEM's obligations under a construction contract for an electric generating facility near Hobbs, New Mexico. For more information, see Note 21.

Contractual obligations and commercial commitments There are no material changes in the Company's contractual obligations relating to estimated interest payments, operating leases, purchase commitments, derivatives, asset retirement obligations, uncertain tax positions and minimum funding requirements for its defined benefit plans for 2014 from those reported in the 2013 Annual Report. The Company's contractual obligations relating to long-term debt at June 30, 2014, increased $332.5 million or 18 percent from December 31, 2013. As of June 30, 2014, the Company's contractual obligations related to long-term debt aggregated $2,187.1 million. The scheduled amounts of redemption (for the twelve months ended June 30, of each year listed) aggregate $42.2 million in 2015; $669.2 million in 2016; $116.0 million in 2017; $63.0 million in 2018; $382.4 million in 2019; and $914.3 million thereafter.



For more information on contractual obligations and commercial commitments, see Part II, Item 7 in the 2013 Annual Report.


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