Any person desiring to intervene or to protest this filing must file in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211, 385.214). Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a notice of intervention or motion to intervene, as appropriate. Such notices, motions, or protests must be filed on or before the comment date. Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant and all the parties in this proceeding.

The Commission encourages electronic submission of protests and interventions in lieu of paper using the "eFiling" link at http://www.ferc.gov. Persons unable to file electronically should submit an original and 14 copies of the protest or intervention to the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426.

This filing is accessible on-line at http://www.ferc.gov, using the "eLibrary" link and is available for review in the Commission's Public Reference Room in Washington, DC. There is an "eSubscription" link on the Web site that enables subscribers to receive e-mail notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please e-mail FERCOnlineSupport@ferc.gov, or call (866) 208-3676 (toll free). For TTY, call (202) 502-8659.

[Page Number 72473]

Comment Date: 5 p.m. Eastern Time on December 1, 2008.

Kimberly D. Bose,

Secretary.

[FR Doc. E8-28286 Filed 11-26-08; 8:45 am]

BILLING CODE 6717-01-P

Vol. 73, No. 230

[Docket No. EL08-89-000]

Notices

Species Act of 1973, as amended (Act). PG&E intends to request a permit to cover 75 species federally listed as threatened or endangered and 34 unlisted species that may become listed during the term of the permit. The permit is needed to authorize incidental take of listed species that could occur as a result of implementing activities covered under the HCP.

The Service provides this notice to: (1) Describe the proposed action and possible alternatives; (2) advise other Federal and State agencies, affected Tribes, and the public of our intent to prepare an EIS/EIR; (3) announce the initiation of a public scoping period; and (4) obtain suggestions and information on the scope of issues and alternatives to be included in the EIS/EIR.

DATES: We must receive your written comments on or before December 26, 2008. We will hold a public meeting on Thursday, December 4, 2008, 2 p.m. to 4 p.m., Sacramento CA.

A Web conference is scheduled for the same date as the public meeting, from 5 p.m. to 7 p.m. Conference Title: PG&E Multiple Region HCP EIS/EIR Scoping. In order to hear the audio for the conference, you must dial: 877-741-4242, and enter passcode: 1495039, for the operator or automated response system. If needed, dial 0 for technical assistance. First you must test your browser for compatibility at the following URL prior to the web event date: https://www112.livemeeting.com/cc/test2007/join?id=LiveMeeting2007Test&role=at tend&cn=user&pw=&recording&_agreement=accepted&placewareLicenseCookie=true

Please note that this is only the browser check link and not the link to the actual event. Once you have successfully joined the test meeting, you may exit. Second, join conference 10 minutes prior to event start: https://www.livemeeting.com/cc/vcc/join?id=w1495039&role=attend&pw=A149503. If you have problems entering the conference using the above link, please type in the meeting URL: https://www119.livemeeting.com/cc/vcc/join and enter the Meeting ID: w1495039, and Entry Code: A149503, when prompted.

ADDRESSES: The public meeting will be held at the following location: Thursday, December 4, 2008, at the Evelyn Moore Community Center, 1402 Dickson Street, Sacramento, CA.

Information, written comments, or questions related to the preparation of the EIS/EIR and NEPA process should be submitted to Eric Tattersall, Chief, Conservation Planning and Recovery Division, U.S. Fish and Wildlife Service, Sacramento Fish and Wildlife Office, 2800 Cottage Way, W-2605, Sacramento, California 95825; Fax 916-414-6713.

FOR FURTHER INFORMATION CONTACT: Eric Tattersall, Chief, Conservation Planning and Recovery Division, at the Sacramento Fish and Wildlife Office at 916-414-6600.

SUPPLEMENTARY INFORMATION:

Reasonable Accommodation

Persons needing reasonable accommodations in order to attend and participate in the public meeting should contact Eric Tattersall at 916-414- 6600 as soon as possible. In order to allow sufficient time to process requests, please submit them at least 1 week before the public meeting. Information regarding this proposed action is available in alternative formats upon request.

Background

Section 9 of the Act and Federal regulations prohibit the "take" of fish and wildlife species listed as endangered or threatened. Under the Act, the following activities are defined as take: To harass, harm, pursue, hunt, shoot, wound, kill, trap, capture or collect listed animal species, or attempt to engage in such conduct [16 U.S.C. 1532(19)]. However, under Section 10(a) of the Act, we may issue permits to authorize "incidental take" of listed species. "Incidental take" is defined by the Act as take that is incidental to, and not the purpose of, carrying out an otherwise lawful activity. Regulations governing permits for threatened species and endangered species, respectively, are at 50 CFR 17.32 and 50 CFR 17.22.

Take of listed plant species is not prohibited under the Act and cannot be authorized under a Section 10(a)(1)(B) permit. However, plant species may be included on a permit in recognition of conservation benefits provided for them under the HCP. All species included on the permit would receive assurances under the Service's "No Surprises" regulation 50 CFR 17.22(b)(5) and 17.32(b)(5).

Currently, PG&E intends to request a permit for 109 species under the HCP: 75 listed and 34 unlisted species (covered species) (Table 1). This proposed species list may change during the development of the HCP. Specific PG&E regions in the Plan Area are abbreviated as follows: CC = Central Coast, NC = North Coast, S = Sierra, and SV = Sacramento Valley. Categories of listing status (Federal, under the Act) are abbreviated as follows: N = not listed, D = de-listed, C = candidate, T = threatened, and E = endangered.

     Table 1--Proposed Covered Species
Species                                  PG&E regions           Listing status *
                                        CC   NC   S    SV
Invertebrates
Conservancy fairy shrimp (Branchinecta                 X    E
conservatio)
Vernal pool fairy shrimp (Branchinecta  X              X    T
lynchi)
Ohlone tiger beetle (Cicindela ohlone)  X                   E
Valley elderberry longhorn beetle                      X    T
(Desmocerus californicus dimorphus)
Smith's blue butterfly (Euphilotes      X                   E
enoptes smithi)
Kern primrose sphinx moth               X                   T
(Euproserpinus euterpe)
Morro shoulderband snail                X                   E
(Helminthoglypta walkeriana)
Vernal pool tadpole shrimp (Lepidurus   X              X    E
packardi)
Lotis blue butterfly (Lycaeides              X              E
argyrognomon lotis)
Shasta crayfish (Pacifastacus fortis)        X              E
Mount Hermon June beetle (Polyphylla    X                   E
barbata)
Behren's silverspot butterfly (Speyeria      X              E
zerene behrensii)
Zayante band-winged grasshopper         X                   E
(Trimerotropis infantilis)
Amphibians:
California tiger salamander--Central              X    X    T
California Distinct Population Segment
(Ambystoma californiense)
California tiger salamander--Santa      X                   E
Barbara County Distinct Population
Segment (Ambystoma californiense)
Santa Cruz long-toed salamander         X                   E
(Ambystoma macrodactylum croceum)
Tehachapi slender salamander            X                   N
(Batrachoseps stebbinsi)
Arroyo toad (Bufo californicus)         X                   E
Shasta salamander (Hydromantes shastae)      X         X    N
California red-legged frog (Rana aurora X    X    X    X    T
draytonii)
Foothill yellow-legged frog (Rana            X         X    N
boylii)
Mountain yellow-legged frog (Rana                 X         C
muscosa)
Southern torrent salamander                  X              N
(Rhyacotriton variegatus)
Reptiles:
Western pond turtle (Clemmys<Actinemys> X    X         X    N
marmorata)
Blunt-nosed leopard lizard (Gambelia    X                   E
silus)
Giant garter snake (Thamnophis gigas)                  X    T
Birds:
Tricolored blackbird (Agelaius          X    X    X    X    N
tricolor)
Golden eagle (Aquila chrysaetos)        X    X    X    X    N
Western burrowing owl (Athene           X              X    N
cunicularia)
Marbled murrelet (Brachyramphus         X    X              T
marmoratus)
Swainson's hawk (Buteo swainsoni)                      X    N
Western snowy plover--Pacific Coast     X    X              T
Population (Charadrius alexandrinus
nivosus)
Western yellow-bill cuckoo (Coccyzus    X              X    C
americanus occidentalis)
Willow flycatcher (Empidonax traillii)  X              X    N
Southwestern willow flycatcher          X                   E
(Empidonax traillii extimus)
American peregrine falcon (Falco        X    X    X    X    D
peregrinus anatum)
Bald eagle (Haliaeetus leucocephalus)   X    X    X    X    D
California black rail (Laterallus       X    X         X    N
jamaicensis coturniculus)
California brown pelican (Pelecanus     X                   E * *
occidentalis californicus)
Purple martin (Progne subis)                           X    N
California clapper rail (Rallus         X    X         X    E
longirostris obsoletus)
Great gray owl (Strix nebulosa)              X    X    X    N
Northern spotted owl (Strix                  X         X    T
occidentalis caurina)
Least Bell's vireo (Vireo bellii        X                   E
pusillus)
Mammals:
San Joaquin antelope ground squirrel    X                   N
(Ammospermophilus nelsoni)
Point Arena mountain beaver (Aplodontia      X              E
rufa nigra)
Giant kangaroo rat (Dipodomys ingens)   X                   E
Fisher--West Coast Distinct Population       X    X    X    C
Segment (Martes pennanti)
San Joaquin kit fox (Vulpes macrotis    X              X    E
mutica)
Plants:
McDonald's rock-cress (Arabis                X              E
mcdonaldiana)
Hearst's Manzanita (Arctostaphylos      X                   N
hookeri ssp. hearstiorum)
Morro Manzanita (Arctostaphylos         X                   T
morroensis)
Marsh sandwort (Arenaria paludicola)    X                   E
Coastal dunes milk-vetch (Astragalus    X                   E
tener var. titi)
San Benito evening-primrose (Camissonia X                   T
benitensis)
California jewel-flower (Caulanthus     X                   E
californicus)
Hearst's ceanothus (Ceanothus           X                   N
hearstiorum)
Maritime ceanothus (Ceanothus           X                   N
maritimus)
Purple amole (Chlorogalum purpureum)--  X                   T
includes both Chlorogalum purpureum
var. purpureum and Chlorogalum
purpureum var. reductum
Howell's spineflower (Chorizanthe            X              E
howellii)
Ben Lomond spineflower (Chorizanthe     X                   E
pungens var. hartwegiana)
Monterey spineflower (Chorizanthe       X                   T
pungens var. pungens)
Scott's Valley spineflower (Chorizanthe X                   E
robusta var. hartwegii)
Robust spineflower (Chorizanthe robusta X                   E
var. robusta)
Chorro Creek bog thistle (Cirsium       X                   E
fontinale var. obispoense)
La Graciosa thistle (Cirsium            X                   E
loncholepis)
Pismo clarkia (Clarkia speciosa ssp.    X                   E
immaculata)
Salt marsh bird's-beak (Cordylanthus    X                   E
maritimus ssp. maritimus)
Palmate-bracted bird's beak                            X    E
(Cordylanthus palmatus)
Seaside bird's-beak (Cordylanthus       X                   N
rigidus ssp. littoralis)
Santa Cruz cypress (Cupressus           X                   E
abramsiana)
Gowen cypress (Cupressus goveniana ssp. X                   T
goveniana)
Gaviota tarplant (Deinandra increscens  X                   E
ssp. villosa)
Indian Knob mountain balm (Eriodictyon  X                   E
altissimum)
Lompoc yerba santa (Eriodictyon         X                   E
capitatum)
Butterworth's buckwheat (Eriogonum      X                   N
butterworthianum)
Red Mountain (Kelloggs') buckwheat           X              C
(Eriogonum kelloggii)
Loch Lomond button-celery (Eryngium          X              E
constancei)
Menzies' wallflower (Erysimum
menziesii)--includes both
Erysimum menziesii ssp. eurekense and        X              E
Erysimum menziesii ssp. yadonii
Santa Cruz wallflower (Erysimum         X                   E
teretifolium)
Monterey gilia (Gilia tenuiflora ssp.   X                   E
arenaria)
Santa Cruz tarplant (Holocarpha         X                   T
macradenia)
Burke's goldfields (Lasthenia burkei)        X              E
Contra Costa goldfields (Lasthenia           X         X    E
conjugens)
Beach layia (Layia carnosa)                  X         X    E
Western lily (Lilium occidentale)            X              E
Nipomo Mesa lupine (Lupinus nipomensis) X                   E
Tidestrom's (clover) lupine (Lupinus    X                   E
tidestromii)
San Joaquin woolly-threads (Monolopia   X                   E
congdonii)
Few-flowered navarretia (Navarretia          X              E
leucocephala ssp. pauciflora)
Many-flowered navarretia (Navarretia         X              E
leucocephala ssp. plieantha)
Lake County stonecrop (Parvisedum            X              E
leiocarpum)
Dudley's lousewort (Pedicularis         X                   N
dudleyi)
White-rayed pentachaeta (Pentachaeta    X                   E
bellidiflora)
Yadon's piperia (Piperia yadonii)       X                   E
San Francisco popcorn-flower            X                   N
(Plagiobothrys diffusus)
Santa Lucia mint (Pogogyne clareana)    X                   N
Scott's Valley polygonum (Polygonum     X                   E
hickmanii)
Hickman's cinquefoil (Potentilla        X                   E
hickmanii)
Gambel's watercress (Rorippa gambellii) X                   E
Adobe sanicle (Sanicula maritime)       X                   N
Red Mountain stonecrop (Sedum                X              C
eastwoodiae)
Cuesta Pass checkerbloom (Sidalcea      X                   N
hickmanii ssp. anomala)
Parish's checkerbloom (Sidalcea         X                   C
hickmanii ssp. parishii)
California seablite (Suaeda             X                   E
californica)
Santa Ynez false lupine (Thermopsis     X                   N
macrophylla)
Kneeland Prairie penny-cress (Thlaspi        X              E
californicum)
Pacific Grove clover (Trifolium         X                   N
polyodon)
Monterey clover (Trifolium trichocalyx) X                   E
   Notes:
   * Species with listing status of D or N are included in the Plan as covered species, in case they become listed during the course of the HCP.

The Plan Area includes approximately 550,000 acres and includes the right- of-way surrounding gas and electric transmission and distribution facilities, the lands owned by PG&E and/or subject to PG&E easements for these facilities, private access routes associated with PG&E's activities, future minor new construction areas, and mitigation areas for impacts resulting from PG&E's activities. The Plan Area includes the network of PG&E facilities in 36 counties, including 18 counties within the Sacramento Valley region, 20 counties within the Sierra region (of which 12 overlap with Sacramento Valley), 6 counties within the Central Coast region, and 4 counties within the North Coast region. The Sacramento Valley region includes the following counties: Tuolumne, Calaveras, Amador, Sacramento, Yolo, Sutter, Butte, Glenn, Yuba, El Dorado, Placer, Nevada, Sierra, Plumas, Colusa, Tehama, Trinity, and Shasta. The counties within the Sierra region include: Modoc, Siskiyou, Lassen, Shasta, Tehama, Butte, Plumas, Sierra, Nevada, Placer, Yuba, El Dorado, Amador, Calaveras, Alpine, Tuolumne, Mariposa, Madera, Fresno, and Tulare. The Central Coast region consists of the following counties: Santa Cruz, San Benito, Monterey, San Luis Obispo, Santa Barbara, and Kern. The North Coast region consists of the following counties: Humboldt, Trinity, Mendocino, and Lake.

Activities that may be covered under the HCP include a variety of tasks associated with the operation, maintenance, and minor new construction of PG&E's gas and electric transmission and distribution system, as mandated for public safety by the California Public Utilities Commission, the California Energy Commission, and the California Department of Transportation. More specifically, these activities may include: gas pipeline protection, recoating, repair, and replacement; electric line protection, repair, reconductoring, and replacement; electric pole repair/replacement; vegetation management to maintain clearances around facilities; and minor construction for new gas and electric extensions. The HCP would not cover operation, maintenance, or construction of power generation facilities. The Service, DFG, and PG&E are now considering components of a conservation program in the HCP. These components would include measures to avoid, minimize, and mitigate take, such as preservation, restoration, and enhancement of habitat. The HCP will also include measures for monitoring and adaptive management. This conservation program would focus on providing long-term protection of covered species by protecting biological communities in the Plan Area. The Service anticipates that PG&E will request a permit duration of 50 years.

Environmental Impact Statement/Report

The joint document will be prepared in compliance with NEPA and the California Environmental Quality Act (CEQA). The Service and DFG will prepare the EIS/EIR, the Service will be responsible for the scope and content of the document for NEPA purposes, and DFG will be responsible for the scope

[Page Number 71672]

and content of the CEQA document, as the State lead agency pursuant to CEQA and the permitting entity pursuant to the California Endangered Species Act and Fish and Game Code 2081.

The EIS/EIR will consider the proposed action (i.e., the issuance of a Section 10(a)(1)(B) permit under the Act based on the proposed HCP) and a reasonable range of alternatives. A detailed description of the proposed action and alternatives will be included in the EIS/EIR. It is anticipated that several alternatives will be developed, which may vary by the level of conservation, impacts caused by the proposed activities, permit area, covered species, or a combination of these factors. Additionally, a No Action alternative will be considered. Under the No Action alternative, the Service would not issue a Section 10(a)(1)(B) permit.

The EIS/EIR will also identify potentially significant impacts on land use and planning, agricultural resources, biological resources, aesthetics, geology and soils, water resources, cultural resources, transportation and circulation, noise and vibration, air quality, public health/environmental hazards, recreation, environmental justice, socioeconomics, and other environmental issues that could occur directly or indirectly with implementation of the proposed action and alternatives. For all potentially significant impacts, the EIS/EIR will identify mitigation measures, where feasible, to reduce these impacts to a level below significance.

This notice of intent is being furnished in accordance with 40 CFR Sections 1501.2, 1501.7, 1506.6, and 1508.22 to obtain suggestions, comments, and useful information from other agencies and the public on the scope of the proposed EIS/EIR, including the significant environmental issues deserving of study, the range of actions, the range of alternatives, and the range of impacts to be considered. Written comments from interested parties are invited to ensure that all issues related to the proposed Section 10(a)(1)(B) incidental take permit application are identified. Comments will only be accepted in written form. You may submit written comments by mail, facsimile transmission, or in person (see ADDRESSES). Before including your address, phone number, e-mail address, or other personal identifying information in your comment, you should be aware that your entire comment--including your personal identifying information--may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.

Dated: November 18, 2008.

Richard E. Sayers,

Acting Deputy Regional Director, California and Nevada Region, Sacramento, California.

[FR Doc. E8-27925 Filed 11-24-08; 8:45 am]

BILLING CODE 4310-55-P

Vol. 73, No. 228

[FWS-R8-ES-2008-N0296; 1112-000-81420-F2]

Notices

In light of the current capital market issues, we remain focused on operating efficiently, controlling discretionary expenses, conserving cash and prudently evaluating the timing of our capital investments in balance with our growth strategy. We are confident in our ability to secure the financing needed for future capital projects to serve our customers and create value for our investors," said David R. Emery, chairman, president and chief executive officer of Black Hills Corp.

For the nine months ended Sept. 30, 2008, income from continuing operations was $44.4 million, or $1.16 per share, compared to $57.5 million, or $1.55 per share, for the same period ended Sept. 30, 2007. Net income for the nine months ended Sept. 30, 2008 was $203.9 million, or $5.31 per share, compared to $75.0 million, or $2.02 per share, reported for the same period in 2007. These year-to-date 2008 results also include the gain from the sale of the IPP assets.

Compared to the third quarter of 2007, income from continuing operations in the third quarter of 2008 was primarily affected by the following factors:

    Utilities
    -- $3.6 million increase in electric utility earnings
    -- $1.9 million decrease in gas utility earnings


    Non-regulated Energy
    -- $4.6 million increase in energy marketing earnings
    -- $4.1 million increase in power generation earnings
    -- $0.3 million decrease in coal mining earnings
    -- $0.5 million decrease in oil and gas earnings

The gas and electric utility earnings include results from the acquisition of the five gas and electric utilities from Aquila on July 14, 2008. Gas utility results were a loss of $1.9 million, consistent with expectations for the seasonality of this business. Electric utility earnings increased due to the January 2008 approved rate recovery for investments made at Cheyenne Light and the inclusion of Colorado Electric utility results. Increases were partially offset by higher fuel and purchased power costs to meet customer demand, as well as, planned and unplanned plant outages during the quarter.

The construction of the 100 MW Wygen III plant remains on schedule and on budget. Additionally, the Colorado PUC recently deemed the company's Electric Resource Plan application complete for the proposed development of 350 MW of natural gas-fired generation, along with 20 MW of renewable energy to serve electric utility customers in southeast Colorado. Regulatory hearings regarding the proposed plans are anticipated to begin in the first quarter of 2009. Black Hills continues to believe the self-build generation proposal provides the most reliable and cost-effective solution to meet the long-term energy needs of utility customers.

Results from power generation increased $4.1 million compared to the same quarter in 2007 and reflects the sale of certain IPP assets and their reclassification to discontinued operations. The increase in power generation earnings includes a $1.7 million after-tax gain on the sale of excess emission credits resulting from the decommissioning of the Ontario plant and an increase in earnings from power fund investments. Third quarter 2007 results included a $1.8 million after-tax impairment loss relating to the Ontario plant.

Overall market conditions and widening Rockies' basis differentials improved results for the energy marketing business during the third quarter and include the effects of mark-to-market impacts. Ongoing execution of long- term transportation deals are building value for 2009 and beyond. The energy marketing team is conservatively managing its cash flows, credit exposure and counterparty risk so that the business continues to operate prudently using its stand-alone credit facility.

Oil and gas production was 11 percent lower compared to third quarter 2007. In response to declining prices in September 2008, the company elected to shut-in two million cubic feet per day of Piceance Basin gas production, which was restored in early October as market conditions improved.

Coal mining earnings were lower as a result of increased mining costs, including overburden removal expenditures, depreciation, diesel fuel prices and coal taxes, but were partially offset by increased production and higher average coal sales prices.

Due to the challenging economic environment, Black Hills is assessing financing alternatives and associated interest rate costs, changes in oil and natural gas pricing and other factors in order to determine the potential impact on earnings, investment and operating expectations. The company expects results to fall within the lower range of 2008 guidance for continuing operations provided on Sept. 17, 2008. The company is reevaluating 2009 guidance and it may be adjusted. "Our growth initiatives remain a priority and our businesses continue to build value. We believe our company is well positioned with a balanced asset portfolio, a defined growth plan, and opportunities to capture the benefits of operating efficiencies as integration plans are completed," concluded Emery.

DIVIDEND

At a meeting held Oct. 29, 2008, the board of directors of Black Hills Corp. declared a quarterly dividend on the common stock. Common shareholders of record at the close of business on Nov. 14, 2008, will receive 35 cents per share, payable on Dec. 1, 2008.

QUARTERLY CONFERENCE CALL AND WEBCAST

The company will conduct a conference call and webcast on Thursday, Nov. 6, 2008, beginning at 11:00 a.m. Eastern Time to discuss recent events and financial and operating performance. To listen to the live broadcast, call 1-800-230-1766. To access the live webcast and download a copy of the investor presentation, go to the Black Hills Web site at http://www.blackhillscorp.com and click "Webcast" in the "Investor Relations" section. The presentation will be posted later today. Listeners should allow at least five minutes registering and accessing the presentation. For those unable to listen to the live broadcast, a replay will be available by telephone through Thursday, Nov. 13, 2008 at 1-800-475-6701 in the United States and at 1-320-365-3844 for international callers. Callers need to enter the access code 966928# when prompted. Also, an archive of the webcast will be available shortly after the call on the Black Hills' Web site.

    CONSOLIDATED FINANCIAL RESULTS

                           Black Hills Corporation
                   (In thousands, except per share amounts)

                            Three Months ended         Nine Months ended
                               September 30,              September 30,
                             2008          2007         2008          2007
    Revenues:
        Utilities         $220,581       $72,275     $413,449      $222,033
        Non-regulated
         energy             71,311        57,892      184,566       199,157
                          $291,892      $130,167     $598,015      $421,190

    Net income (loss):
      Continuing
       operations -
        Utilities           $8,911        $7,189      $28,631       $22,884
        Non-regulated
         energy             12,672         4,727       23,670        36,334
        Corporate           (2,061)         (787)      (7,889)       (1,720)
        Income from
         continuing
         operations         19,522        11,129       44,412        57,498
        Discontinued
         operations (a)    145,389         6,335      159,486        17,518
        Net income        $164,911       $17,464     $203,898       $75,016

    Weighted average common
     shares outstanding:
        Basic               38,307        37,643       38,145        36,810
        Diluted             38,425        38,078       38,430        37,226

    Earnings per share:
        Basic -
          Continuing
           operations        $0.51         $0.30        $1.16         $1.56
         Discontinued
          operations          3.79          0.17         4.18          0.48
          Total              $4.30         $0.47        $5.34         $2.04
        Diluted -
          Continuing
           operations        $0.51         $0.29        $1.16         $1.55
          Discontinued
           operations         3.78          0.17         4.15          0.47
          Total              $4.29         $0.46        $5.31         $2.02

    (a)   2008 and 2007 discontinued operations primarily reflect the after-
          tax results of operations of the Company's seven IPP power
          generation plants that were sold on July 11, 2008. Prior periods
          have been adjusted to reflect this reclassification to discontinued
          operations.



    BUSINESS UNIT QUARTERLY PERFORMANCE SUMMARY
    (Minor differences in comparative amounts may result due to rounding)

Utilities

Income from continuing operations from the utilities for the three-month period ended Sept. 30, 2008 was $8.9 million, compared to $7.2 million in 2007. Results were as follows:

     --   Electric utilities' income from continuing operations was
          $10.8 million in 2008 and $7.2 million in 2007.  Operating income in
          2008 increased $8.1 million reflecting increased gross margins of
          $23.7 million primarily due to the acquired Colorado electric
          utility and the inclusion of Wygen II in Cheyenne Light's rate base
          effective on Jan. 1, 2008.  Operating expenses increased due to
          depreciation and operating costs associated with the Wygen II plant
          and the operating expenses of the acquired Colorado electric
          utility.
     --   Gas utilities' loss from continuing operations was $1.9 million in
          2008.  Results from gas utilities reflect the addition of gas
          utilities acquired from Aquila on Jul. 14, 2008.  Losses for the
          quarter were consistent with expectations and not unusual for off-
          peak seasons.


    The following tables provide certain utility operating statistics:



                           Three months ended          Nine months ended
                               September 30,               September 30,
    Electric Utilities      2008           2007         2008          2007
    Retail sales-MWh     1,118,937       712,302     2,450,358    1,987,155
    Contracted wholesale
     sales - MWh           229,074       169,211       678,608      486,149
    Off-system sales -
     MWh                   321,231       141,930       832,742      426,143
                         1,669,242     1,023,443     3,961,708    2,899,447
    Regulated power plant
     availability:
      Coal-fired plants       96.4%         96.6%         93.2%*        95.5%
      Other plants            98.7%         99.8%         92.6%        99.6%
      Total availability      97.3%         98.0%         93.0%        97.3%

    * Reflects major maintenance outages at our Ben French, Osage and Neil
      Simpson I coal-fired plants



    Gas Utilities (acquired July 14, 2008)

    Gas sales -
     Dekatherm (Dth)     5,181,662             -     5,181,662            -

Non-regulated Energy

Income from continuing operations from non-regulated energy for the three- month period ended Sept. 30, 2008 was $12.7 million, compared to $4.7 million in 2007. Business results were as follows:

     --   Energy Marketing income from continuing operations was $6.9 million,
          compared to $2.3 million in 2007.
               o    A $30.9 million pre-tax increase in unrealized marketing
                    margins.
               o    Lower incentive compensation costs related to the
                    decreased realized gas marketing margins.
               Partially offset by:
               o    A $22.1 million pre-tax decrease in realized gas marketing
                    margins primarily resulting from prevailing conditions in
                    natural gas markets affecting both transportation and
                    storage strategies.  In addition, crude oil marketing
                    margins were lower due to the impact of decreasing
                    commodity prices on inventory held to meet pipeline
                    requirements.
     --   Power Generation income from continuing operations was $3.2 million
          in 2008, compared to a loss of $0.9 million in 2007.
               o    The sale of excess emission credits resulting from the
                    decommissioning of the Ontario plant for $1.7 million
                    after-tax;
               o    The recording of an impairment loss, and related costs, in
                    the third quarter of 2007 of $1.8 million after-tax
                    relating to the Ontario plant; and
               o    Allocated indirect corporate costs and inter-segment
                    interest expense, related to the IPP assets sold and not
                    reclassified to discontinued operations, of $3.2 million
                    after-tax for the three months ended Sept. 30, 2007.
               Partially offsetting these increases were the following:
               o    Lower earnings from the Wygen I and Gillette CT plants
                    primarily due to higher interest costs partially offset by
                    lower purchased power costs in 2008.
     --   Oil and Gas income from continuing operations was $1.5 million in
          2008, compared to $2.0 million in 2007.
               o    A $0.5 million increase in LOE.
               o    A $1.1 million increase in production taxes due to higher
                    oil prices.
               Partially offsetting these increased expenses were the
               following:
               o    Revenue increased $1.1 million due to a 34 percent
                    increase in the average hedged price of oil received
                    partially offset by a 2 percent decrease in average hedged
                    price of gas received, and lower production of 11 percent.
                    The lower production reflects permitting delays, the
                    temporary shut-in of Piceance Basin gas production, and
                    delayed drilling activities on our non-operated
                    properties.
     --   Coal Mining income from continuing operations was $1.1 million in
          2008, compared to $1.4 million in 2007.   Results were impacted by
          the following:
               o    Operating expenses increased $4.9 million, or 53 percent,
                    during the three months ended Sept. 30, 2008 primarily due
                    to increased overburden removal costs, an increase in
                    diesel fuel costs, increased coal taxes due to a higher
                    revenue base and increased depreciation due to increased
                    equipment usage.  We had a 54 percent increase in cubic
                    yards of overburden moved.
               Partially offsetting the increased expenses was the following:
               o    Revenue increased $5.6 million, or 53 percent, for the
                    three month period ended Sept. 30, 2008 compared to the
                    same period in 2007.  Revenues increased due to an
                    increase in average price received and higher quantity of
                    tons of coal sold, primarily due to additional sales to
                    Cheyenne Light for Wygen II and increased train load-out
                    sales.


    The following tables contain certain Non-regulated Energy operating
statistics:



                              Three months ended          Nine months ended
                                 September 30,               September 30,
                              2008          2007          2008          2007
    Coal mining:
    Tons of coal sold        1,521         1,314         4,518        3,796
    Cubic yards of
     overburden moved        3,368         2,188         9,021        5,402
    Oil and gas
     production:
    Mcf equivalent sales 3,444,841     3,890,760    10,081,574   10,994,141
    Energy marketing
     average daily
     volumes:
    Natural gas physical
      - MMBtus           1,854,100     1,859,100     1,749,600    1,779,400
    Crude oil physical
     - barrels               7,800        10,200         7,300        9,000



                             Three months ended          Nine months ended
                                September 30,               September 30,
    Power generation:         2008          2007          2008         2007
    Contracted fleet power
     plant availability:
      Coal-fired plant        96.8%         95.3%         95.6%        94.3%
      Natural gas-fired
       plants                 99.4%         94.7%         82.5%        85.5%
      Total availability      97.8%         95.0%         94.8%        94.9%

Service Company (Corporate)

Results for the three-month period ended Sept. 30, 2008 were a $2.1 million loss, compared to a loss of $0.8 million for the same period in 2007. Results were affected by increased unallocated costs in the three months ended Sept. 30, 2008, compared to the same period in 2007, primarily as a result of increased incentive compensation costs related to the IPP sale and the acquisition of the five gas and electric utilities from Aquila.

Discontinued Operations

Earnings from discontinued operations were $145.4 million for the three month period ended Sept. 30, 2008, compared to $6.3 million for the same period in 2007. The 2008 results contain $141.7 million of income attributable to the after-tax gain on the sale of IPP assets that closed on July 11, 2008.

ABOUT BLACK HILLS CORPORATION

Black Hills Corp. is a diversified energy company with a tradition of exemplary service and a vision to be the energy partner of choice is based in Rapid City, S.D. with corporate offices in Golden, Colo. and Omaha, Neb. The company serves 750,000 utility customers in Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. The company's non-regulated businesses generate wholesale electricity, produce natural gas, oil and coal, and market energy. Black Hills employees partner to produce results that improve life with energy. More information is available at http://www.blackhillscorp.com.

CAUTION REGARDING FORWARD-LOOKING STATEMENTS

This news release includes "forward-looking statements" as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this release that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward- looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward- looking statements, including the risk factors described in Item 1A of Part I of our 2007 Annual Report on Form 10-K filed with the SEC, and other reports that we file with the SEC from time-to-time, and the following:

     --   Our ability to obtain adequate cost recovery for our utility
          operations through regulatory proceedings; to receive favorable
          rulings in periodic applications to recover costs for fuel,
          transmission and purchased power in our regulated utilities, and our
          ability to add power generation assets into our regulatory rate
          base;
     --   Our ability to successfully integrate and profitably operate the
          five gas and electric utilities recently acquired from Aquila;
     --   Our ability to successfully maintain or improve our corporate credit
          rating;
     --   Our ability to complete the planning, permitting, construction,
          start up and operation of power generating facilities in a cost-
          effective and timely manner;
     --   Our ability to meet production targets for our oil and gas
          properties, which may be dependent upon issuance by federal, state,
          and tribal governments, or agencies thereof, of drilling,
          environmental and other permits, and the cost and availability of
          specialized contractors, work force, and equipment;
     --   The timing, volatility and extent of changes in energy-related and
          commodity prices, interest rates, foreign exchange rates, energy and
          commodity supply or volume, the cost and availability of
          transportation of commodities, and demand for our services, all of
          which can affect our earnings, liquidity position and the underlying
          value of our assets;
     --   Counterparty credit risk;
     --   Capital market conditions and market uncertainties related to credit
          and interest rates, which may affect our ability to raise capital on
          favorable terms or at all;
     --   Other factors discussed from time to time in our filings with the
          SEC.

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events, or otherwise.

SOURCE Black Hills Corp.

http://www.blackhillscorp.com

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