The credit facility includes customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions and maintenance of the following financial covenants:
If these covenants are violated, it would be considered an event of default entitling the lenders to terminate the remaining commitment and accelerate all principal and interest outstanding.
A default under the credit facility may be triggered by events such as a failure to comply with financial covenants or certain other covenants under the credit facility, a failure to make payments when due or a failure to make payments when due in respect of, or a failure to perform obligations relating to, other debt obligations of $20 million or more. A default under the credit facility would permit the participating banks to restrict our ability to further access the credit facility for loans or new letters of credit, require the immediate repayment of any outstanding loans with interest and require the cash collateralization of outstanding letter of credit obligations.
The credit facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result, after giving effect to such action.
Enserco, our Energy Marketing segment, has a $300 million uncommitted, discretionary line of credit to provide support for the purchase and sale of natural gas and crude oil through the issuance of letters of credit. The line of credit is secured by all of Enserco’s assets. At September 30, 2008, there were outstanding letters of credit issued under the facility of $143.8 million, with no borrowing balances outstanding on the facility. This credit facility expires May 8, 2009.
The Enserco credit facility may be impacted by the current global credit crisis. The credit crisis is prompting most commercial banks to reduce their commitments, or deleverage their portfolios. Consequently, some of the Enserco credit facility participating banks may decline to participate in new credit transactions under the facility. Should a bank decline to participate in the facility, the existing issued letters of credit would remain in place. The available capacity of the $300 million Enserco facility, however, would be reduced by that bank’s pro rata participation under the facility for future transactions.
The two largest participating banks under our $300 million Enserco credit facility are Fortis Capital Corp. and BNP Paribas, having participation levels of $105 million and $75 million, respectively. On September 29, 2008, after the deterioration in the financial strength of the Fortis bank group, the governments of Belgium, Luxembourg and the Netherlands agreed to invest EUR 11.2 billion in Fortis. In conjunction with the announcement, the senior unsecured credit ratings of Fortis Bank SA/NV, the entity which issues letters of credit under the Enserco credit facility, were reduced from Aa3 to A1 by Moody’s, and from A+ to A by Standard and Poor’s.
On October 6, 2008 BNP Paribas announced that it had agreed to acquire control of Fortis’ operations in Belguim and Luxembourg, as well as the international banking franchises, which includes Fortis Capital Corp; the participating bank in the Enserco credit facility. Closing on the transaction is subject to antitrust and regulatory approvals, and is expected to take place by year end or in the first quarter of 2009.
Upon completion of the acquisition of Fortis by Paribas, it is expected that the two entities will continue to operate as stand-alone entities for a certain period of time. It is uncertain, however, as to whether the two entities, either before or after the acquisition is effected, will continue to participate in the Enserco facility at their current levels.
Because of the uncommitted nature of the Enserco facility, and given the current condition of credit markets, we are conducting our Enserco business operations in a manner to conserve our utilization of the facility. We intend to pursue a committed credit facility for Enserco to replace the current facility upon its May 8, 2009 expiration.
2008 Financing Transactions
On May 7, 2007, we entered into a senior unsecured $1.0 billion Acquisition Facility with ABN AMRO Bank N.V. as administrative agent and other banks to provide for funding for our acquisition of Aquila’s electric utility in Colorado and its gas utilities in Colorado, Kansas, Nebraska and Iowa. The Acquisition Facility is a committed facility to fund an acquisition term loan in a single draw in an amount up to $1.0 billion. On July 14, 2008, in conjunction with the completion of the purchase of the Aquila properties, we executed a single draw of $383 million under the Acquisition Facility; no additional borrowing capacity is thus available under the acquisition facility. The loan termination date is February 5, 2009.
Borrowings under the Acquisition Facility can be made under a base rate option, which is based on the then-current prime rate, or under a LIBOR option, which is based on the then-current LIBOR plus an applicable margin. The applicable margin for LIBOR borrowings is 55 basis points during the period from the initial funding under the term loan to six months thereafter and 67.5 basis points during the period from six months and one day after the initial funding to the loan maturity. The facility contains certain customary affirmative and negative covenants which largely replicate the covenants under our existing revolving credit facility.
We initially funded the payment for our June 2008 project debt maturity of $128.3 million on the Wygen I facility through borrowings on our revolving credit facility.
In conjunction with the sale of the IPP assets, the $67.5 million project financing debt for our Colorado facility was paid off.
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Future Financing Plans
We previously planned to complete a senior unsecured long-term holding company debt offering of $450 million or more in the fourth quarter of 2008, with a portion of the proceeds to be used to pay off the $383 million borrowing on the Acquisition Facility, and the remaining proceeds used to reduce borrowings on the revolving credit facility. The current global financial crisis has caused a widespread contraction in the availability of credit from the commercial bank markets and debt capital markets, as well as a sharp increase in credit risk premiums.
Because of the increase in long-term credit risk premiums and the reduction in capacity in the debt capital markets, we are reviewing and considering other alternatives to a senior unsecured long-term holding company debt offering. Those alternatives include an extension of all or a portion of the Acquisition Facility borrowing to a maturity date of late 2009 or later, or a new term loan in the amount of $200 million or more, with a one to three year maturity date. In the interim, we continue to prepare for and include as a financing alternative a long-term debt issuance, which will be evaluated based upon further developments in the debt capital markets.
If we are unable to complete a replacement debt financing or an extension of the Acquisition Facility financing, we will consider implementing alternative measures to conserve or raise capital. These alternatives could include deferring our planned capital expenditure program, implementing asset sales, issuing equity, reducing or eliminating our dividend payments, or curtailing certain business activities, including our marketing operations. If we cannot complete capital conservation or capital raising alternatives at sufficient levels, we may be unable to repay all or a portion of the $383 million Acquisition Facility loan, which is due on February 5, 2009.
Interest Rate Swaps
The Company has forward starting interest rate swaps with a notional amount of $250.0 million. These swaps were entered into for the purpose of hedging interest rate movements that would impact long-term financings that were originally expected to occur in 2008. The swaps were designated as cash flow hedges in accordance with SFAS 133 and at September 30, 2008, they had a mark-to-market value of $(28.1) million, which was recorded in “Accumulated other comprehensive loss” on the Condensed Consolidated Balance Sheet.
Subsequent to September 30, 2008, based on credit market conditions that transpired in October, the Company determined that the forecasted long-term debt financings were no longer probable of occurring. The Company continues to evaluate its near term financing alternatives, which may include long-term financings and/or the use of other financing alternatives with a shorter duration. As a result of the originally forecasted long-term financings no longer being probable of occurring within the originally specified time period, the swaps were no longer effective hedges in accordance with SFAS 133 and hedge relationships were de-designated. On the date of de-designation, the swaps had a mark-to-market value of approximately $(42.7) million. This value will remain in “Accumulated other comprehensive loss” and subsequent mark-to-market adjustments to the swaps will be recorded within the income statement.
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These subsequent mark-to-market adjustments could have a significant impact on our results of operations. A 100 basis point move in the interest rate curves over the term of the swaps would have a pre-tax impact of approximately $31.7 million. Should the Company complete a long-term financing with terms that are closely correlated to the hedged forecasted transactions, then the amount in “Accumulated other comprehensive loss” will be amortized and recorded as interest expense over the term of the underlying debt. If the Company determines that the long-term financing is probable of not occurring by the end of the originally specified time period, the balance in “Accumulated other comprehensive loss” related to the swaps will be immediately recorded as a charge to earnings.
Counterparty Credit Risk
Another risk arising from current global financial conditions is increased potential for exposure to counterparty credit default. We have established guidelines, controls, and limits to manage and mitigate credit risk. For our energy marketing, production and generation activities, we seek to mitigate our credit risk by conducting a majority of our business with investment grade companies, setting tenor and credit limits commensurate with counterparty financial strength, obtaining netting agreements, and securing our credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit and other security agreements. Through this current credit crisis we have been aggressively observing and evaluating any changes in our counterparties’ credit status and adjusting the credit limits based upon the customer’s current creditworthiness. Through this aggressive monitoring, we have been able to avoid any significant credit losses during the current credit crisis.
On September 14th, 2008, Lehman Brothers Holdings Inc. (Lehman) and several of its subsidiaries filed for bankruptcy. Enserco has physical and financial gas transactions with Lehman Energy Commodity Services, Inc., (LECS), a Lehman subsidiary. Enserco has approximately $0.4 million in money owed to Enserco by LECS for forward mark-to-market natural gas financial transactions. Enserco owes LECS approximately $0.4 million for forward physical natural gas transactions. The Company believes it has setoff rights among the transactions; in the event the Company was not able to execute setoff rights, the Company would have a loss exposure of $0.4 million pretax.
Corporate Credit Rating Update
Our corporate credit rating by Moody’s was “Baa3” during the first six months of 2008; on July 15, 2008, Moody’s revised the outlook of our credit rating from negative to stable. Our corporate credit rating by S&P was “BBB-;” the outlook is stable. On July 15, 2008 we received a BBB issuer default rating from Fitch.
There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 2007 Annual Report on Form 10-K filed with the SEC.
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Capital Requirements
During the nine months ended September 30, 2008, capital expenditures were approximately $244.9 million for property, plant and equipment additions, which were partially financed through approximately $25.5 million of accrued liabilities. We currently expect total capital expenditures for 2008, excluding the Aquila asset acquisition, to approximate $401.0 million. This sum includes, but is not limited to: $27.8 million related to the Valencia 149 MW, simple-cycle gas turbine generating facility located near Albuquerque, New Mexico which was sold as part of the IPP asset sale; $76.2 million for the 100 MW Wygen III power plant located near Gillette, Wyoming (with the assumption we retain 75 percent ownership in the plant); $56.3 million related to maintenance capital for our new utility properties; $17.0 million for the acquisition of non-operated oil and gas interests; and $84.1 million within our Oil and Gas segment primarily for maintenance capital and development drilling.
As result of the current global credit crisis we are re-evaluating all of our forecasted capital expenditures, and if determined prudent, may defer some of these expenditures for a period of time. Future projects are dependent upon the availability of attractive economic opportunities, and as a result, actual expenditures may vary significantly from forecasted estimates.
Forecasted capital requirements for maintenance capital and development capital are as follows:
| Nine Months Ended | Total |
| September 30, 2008 | 2008 Planned |
| Expenditures | Expenditures |
| (in thousands) |
Utilities: (1) | | |
Electric Utilities – Wygen III(2) | $ | 76,427 | $ | 79,321 |
Electric Utilities (3)(4) | | 46,243 | | 116,247(6) |
Gas Utilities(4) | | 12,188 | | 35,773 |
Non-regulated Energy: | | | | |
Oil and Gas(4) | | 62,420 | | 84,100 |
Power Generation - Valencia(5) | | 27,847 | | 30,600 |
Power Generation | | 1,661 | | 5,802(6) |
Coal Mining | | 16,820 | | 22,070 |
Energy Marketing | | 21 | | 135 |
Corporate (including Aquila | | | | |
acquisition costs) | | 26,098 | | 27,000 |
| $ | 269,725 | $ | 401,048 |
__________________________
(1) | Forecasted capital requirements are exclusive of the $940.0 million purchase price and related other costs for the acquisition of Aquila utility assets in 2008. |
(2) | Forecasted expenditures of the Wygen III coal-fired plant reflect our expectation that we will retain a 75 percent ownership interest in the plant. |
(3) | Electric Utilities capital requirements include approximately $17.2 million for transmission projects in 2008. |
(4) | Capital expenditures include expenditures of the acquired utilities subsequent to the acquisition date. |
(5) | The Valencia power plant was included in the IPP assets sold July 11, 2008. |
(6) | Forecasted capital requirements include $8.0 million of project costs for air-cooled condenser upgrades for our Neil Simpson II and Wygen I coal-fired plants. Total project costs are expected to be approximately $16.2 million and will add approximately 8.2 MW of rated capacity to each plant. This represents additional base load installed capacity at approximately $995 per kilowatt. |
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Contractual Obligations
Unconditional purchase obligations for firm transportation and storage fees for our Energy Marketing segment increased $44.9 million from $47.9 million at December 31, 2007 to $92.8 million at September 30, 2008. Approximately $47.8 million of the fee obligations relate to the 2009-2011 period with the remaining occurring thereafter.
See Note 14 to our consolidated financial statements for purchase obligations related to our acquired utilities.
In addition, contractual obligations of $14.0 million related to the IPP plants sold consisted of $12.7 million of land lease obligations for the Arapahoe, Valmont and Harbor power plants and $1.3 million for a Las Vegas II transmission agreement. These obligations were previously reported as purchase obligations in the Liquidity section of Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in our 2007 Annual Report on Form 10-K.
Guarantees
See Note 6 to our consolidated financial statements.
New Accounting Pronouncements
Other than the new pronouncements reported in our 2007 Annual Report on Form 10-K filed with the SEC and those discussed in Notes 2 and 3 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements issued that when implemented would require us to either retroactively restate prior period financial statements or record a cumulative catch-up adjustment.
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FORWARD-LOOKING INFORMATION
This report contains forward-looking information. Forward-looking information involves risks and uncertainties, and certain important factors can cause actual results to differ materially from those anticipated. The forward-looking statements contained in this report include:
• We expect to refinance in the bank loan markets or the debt capital markets the acquisition debt we incurred in the Aquila Transaction before the acquisition loan matures in the first quarter of 2009. Some important factors that could cause actual results to differ materially from those anticipated include: |
|
§ Our ability to access the bank loan and debt capital markets depends on market conditions beyond our control. If the credit markets remain tight and do not improve, we may not be able to permanently finance our acquisition debt on reasonable terms, if at all. |
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§ Our ability to raise capital in the debt capital markets depends upon our financial condition and credit ratings, among other things. If our financial condition deteriorates unexpectedly, or our credit ratings are lowered, we may not be able to permanently finance the acquisition debt on reasonable terms, if at all. |
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• We anticipate that our existing credit capacity and available cash will be sufficient to fund our working capital needs and capital requirements. Some important factors that could cause actual results to differ materially from those anticipated include: |
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§ Our access to revolving credit capacity depends on maintaining compliance with loan covenants. If we violate these covenants, we may lose revolving credit capacity and not have sufficient cash available for our peak winter needs and other working capital requirements, and our forecast capital expenditure requirements. |
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§ Counterparties may default on their obligations to supply commodities, return collateral to us, or otherwise meet their obligations under commercial contracts, including those designed to hedge against movements in commodity prices. |
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§ Access to our uncommitted $300 million Enserco facility depends on the willingness of the participating banks to continue to participate in extensions of credit requested under the facility. Given the ongoing credit crisis, participating banks could decide to stop participating in the facility. |
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• In connection with the IPP Transaction, we expect to defer tax payments in the range of $135 million to $160 million. Some important factors that could cause actual results to differ materially from those anticipated include: |
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§ The IRS could challenge and rule against our deferred tax strategies, which could impair our ability to defer all or part of these tax payments. |
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• We expect to sell to MDU a minority interest in our Wygen III project under construction. Some important factors that could cause actual results to differ materially from those anticipated include: |
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§ We have not entered into definitive transaction agreements with MDU with respect to the proposed sale transaction. If we are not able to reach an agreement with MDU on the terms and conditions upon which the sale would be consummated, we will not be able to complete the anticipated sale transaction. |
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§ In the event we enter into definitive transaction agreements with MDU, we or MDU may not be able to satisfy one or more of the conditions required to complete the sale transaction. |
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• We expect to complete the sale of a minority interest in Wygen I to MEAN this year. Some important factors that could cause actual results to differ materially from those anticipated include: |
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§ MEAN may not be able to arrange the acquisition financing required to complete the announced sale transaction. |
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§ We or MEAN may not be able to satisfy one or more of the other conditions required to be satisfied in order to consummate the sale transaction. |
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• We intend to replace the uncommitted $300 million Enserco facility with a committed credit facility prior to its May 2009 expiration date. Some important factors that could cause actual results to differ materially from those anticipated include: |
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§ Our ability to access the bank loan market depends on market conditions beyond our control. If the credit environment remains tight and does not improve, we may not be able to replace the uncommitted facility with a committed credit line on reasonable terms, if at all. |
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§ Our ability to obtain a committed credit facility for Enserco upon reasonable terms, if at all, may depend on, among other factors, our ability to pledge Enserco assets or otherwise provide credit support to lenders willing to participate in a committed credit facility. |
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• We expect to make contributions to our defined benefit contribution plans of approximately $14.5 million in 2009. Some important factors that could cause actual contributions to differ materially from anticipated amounts include: |
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§ The actual value of the plans’ invested assets at December 31, 2008. |
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§ The discount rate used in determining the funding requirement. |
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Utilities
We produce, purchase and distribute power in four states and purchase and distribute natural gas in five states. All of our gas distribution utilities have purchased gas adjustment (PGA) provisions that allow them to pass the prudently-incurred cost of gas through to the customer. To the extent that gas prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to “true-up” billed amounts to match the actual natural gas cost we incurred. These adjustments are subject to periodic prudence reviews by the state utility commissions. In Colorado, Montana, South Dakota, and Wyoming, we have a mechanism for our electric utilities that serves a purpose similar to the PGAs for our gas utilities. To the extent that our fuel and purchased power energy costs are higher or lower than the energy cost built into our tariffs, the difference (or a portion thereof) is passed through to the customer.
The fair value of our Utilities derivative contracts at September 30, 2008 are summarized below (in thousands):
| September 30, |
| 2008 |
| | |
Net derivative assets (liabilities) | $ | 9,424 |
Cash collateral | | 12,750 |
| | |
| $ | 22,174 |
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Non Regulated Trading Activities
The following table provides a reconciliation of activity in our natural gas and crude oil marketing portfolio that has been recorded at fair value including market value adjustments on inventory positions that have been designated as part of a fair value hedge during the nine months ended September 30, 2008 (in thousands):
Total fair value of energy marketing positions marked-to-market at December 31, 2007 | $ | 3,718 (a) |
Net cash settled during the period on positions that existed at December 31, 2007 | | 19,389 |
Change in fair value due to change in assumptions | | 1,898 |
Unrealized gain on new positions entered during the period and still existing at | | |
September 30, 2008 | | 44,269 |
Realized loss on positions that existed at December 31, 2007 and were settled during | | |
the period | | (26,413) |
Change in cash collateral(b) | | (502) |
Unrealized gain on positions that existed at December 31, 2007 and still exist at | | |
September 30, 2008 | | (13,807) |
| | |
Total fair value of energy marketing positions at September 30, 2008 | $ | 28,552 (a) |
_____________________________
(a) | The fair value of energy marketing positions consists of derivative assets/liabilities held at fair value in accordance with SFAS 157 and market value adjustments to natural gas inventory that has been designated as a hedged item as part of a fair value hedge in accordance with SFAS 133, as follows (in thousands): |
| September 30, | June 30, | March 31, | December 31, |
| 2008 | 2008 | 2008 | 2007 |
| | | | | | | | |
Net derivative assets (liabilities) | $ | 45,392 | $ | (1,606) | $ | (8,475) | $ | 14,797 |
Cash collateral | | (1,789) | | 49,050 | | 32,876 | | (1,287) |
Market adjustment recorded | | | | | | | | |
in material, supplies and fuel | | (15,051) | | 6,312 | | 4,551 | | (9,792) |
| | | | | | | | |
| $ | 28,552 | $ | 53,756 | $ | 28,952 | $ | 3,718 |
(b) | The Company adopted FSP FIN 39-1 effective January 1, 2008. See Note 2 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. |
GAAP restricts mark-to-market accounting treatment primarily to only those contracts that meet the definition of a derivative under SFAS 133. Therefore, the above reconciliation does not present a complete picture of our overall portfolio of trading activities or our expected cash flows from energy trading activities. In our natural gas and crude oil marketing operations, we often employ strategies that include utilizing derivative contracts along with inventory, storage and transportation positions to accomplish the objectives of our producer services, end-use origination and wholesale marketing groups. Except in circumstances when we are able to designate transportation, storage or inventory positions as part of a fair value hedge, SFAS 133 generally does not allow us to mark our inventory, transportation or storage positions to market. The result is that while a significant majority of our energy marketing positions are fully economically hedged, we are required to mark some parts of our overall strategies (the derivatives) to market value, but are generally precluded from marking the rest of our economic hedges (transportation, inventory or storage) to market. Volatility in reported earnings and derivative positions should be expected given these accounting requirements.
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We adopted the provisions of SFAS 157 on January 1, 2008. SFAS 157 provides a single definition of fair value and establishes a fair value hierarchy which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. We use the fair value methodology outlined in SFAS 157 to value the assets and liabilities for our outstanding derivative contracts. See Note 12 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
The sources of fair value measurements were as follows (in thousands):
| Maturities |
Source of Fair Value | Less than 1 year | 1 – 2 years | Total Fair Value |
| | | | | | |
Level 1 | $ | (1,789) | $ | — | $ | (1,789) |
Level 2 | | 41,310 | | 1,536 | | 42,846 |
Level 3 | | 4,995 | | (2,449) | | 2,546 |
Market value adjustment for inventory | | | | | | |
(see footnote (a) above) | | (15,051) | | — | | (15,051) |
| | | | | | |
Total | $ | 29,465 | $ | (913) | $ | 28,552 |
The following table presents a reconciliation of our September 30, 2008 energy marketing positions recorded at fair value under GAAP to a non-GAAP measure of the fair value of our energy marketing forward book wherein all forward trading positions are marked-to-market (in thousands):
Fair value of our energy marketing positions marked-to-market in accordance with GAAP | | |
(see footnote (a) above) | $ | 28,552 |
Market value adjustments for inventory, storage and transportation positions that are | | |
part of our forward trading book, but that are not marked-to-market under GAAP | | 87,614 |
Fair value of all forward positions (non-GAAP) | | 116,166 |
Cash collateral included in GAAP marked-to-market fair value | | 1,789 |
Fair value of all forward positions excluding cash collateral (non-GAAP) | $ | 117,955 |
There have been no material changes in market risk faced by us from those reported in our 2007 Annual Report on Form 10-K filed with the SEC. For more information on market risk, see Part II, Items 7 and 7A. in our 2007 Annual Report on Form 10-K, and Note 12 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
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Activities Other Than Trading
The Company has entered into agreements to hedge a portion of its estimated 2008, 2009 and 2010 natural gas and crude oil production from the Oil and Gas business segment. The hedge agreements in place are as follows:
Natural Gas
Location | Transaction Date | Hedge Type | Term | Volume | Price |
| | | | (MMBtu/day) | |
San Juan El Paso | 11/29/2006 | Swap | 01/08 – 12/08 | 5,000 | $ | 7.44 |
San Juan El Paso | 11/29/2006 | Swap | 11/07 – 12/08 | 3,000 | $ | 7.49 |
San Juan El Paso | 01/04/2007 | Swap | 04/08 – 03/09 | 2,500 | $ | 6.93 |
San Juan El Paso | 01/04/2007 | Swap | 04/08 – 03/09 | 1,000 | $ | 6.96 |
San Juan El Paso | 01/05/2007 | Swap | 01/09 – 03/09 | 1,500 | $ | 7.51 |
San Juan El Paso | 01/10/2007 | Swap | 04/08 – 12/08 | 1,500 | $ | 6.88 |
San Juan El Paso | 01/11/2007 | Swap | 04/08 –12/08 | 2,000 | $ | 6.81 |
San Juan El Paso | 02/12/2007 | Swap | 01/09 – 03/09 | 5,000 | $ | 7.87 |
San Juan El Paso | 04/25/2007 | Swap | 04/09 – 06/09 | 2,500 | $ | 7.21 |
San Juan El Paso | 04/26/2007 | Swap | 04/09 – 06/09 | 2,500 | $ | 7.15 |
San Juan El Paso | 05/09/2007 | Swap | 04/09 – 06/09 | 5,000 | $ | 7.24 |
CIG | 05/09/2007 | Swap | 04/09 – 06/09 | 2,000 | $ | 6.87 |
CIG | 05/09/2007 | Swap | 01/09 – 03/09 | 2,000 | $ | 8.37 |
San Juan El Paso | 07/27/2007 | Swap | 07/09 – 09/09 | 5,000 | $ | 7.63 |
CIG | 09/07/2007 | Swap | 07/09 – 09/09 | 1,500 | $ | 6.48 |
CIG | 09/07/2007 | Swap | 04/08 – 12/08 | 1,500 | $ | 5.91 |
AECO | 09/07/2007 | Swap | 04/08 – 10/09 | 1,000 | $ | 6.89 |
San Juan El Paso | 10/29/2007 | Swap | 07/09 – 09/09 | 5,000 | $ | 7.38 |
San Juan El Paso | 10/29/2007 | Swap | 10/09 – 12/09 | 5,000 | $ | 7.53 |
CIG | 10/29/2007 | Swap | 10/09 – 12/09 | 1,500 | $ | 7.07 |
NWR | 11/16/2007 | Swap | 01/09 – 12/09 | 1,500 | $ | 6.87 |
San Juan El Paso | 11/16/2007 | Basis Swap | 04/08 – 12/08 | -1,500 | $ | (0.93) |
NWR | 11/16/2007 | Basis Swap | 04/08 – 12/08 | 1,500 | $ | (1.64) |
San Juan El Paso | 12/13/2007 | Swap | 10/09 – 12/09 | 1,500 | $ | 7.39 |
San Juan El Paso | 12/13/2007 | Swap | 10/09 – 12/09 | 1,500 | $ | 7.41 |
CIG | 01/03/2008 | Swap | 01/10 – 03/10 | 2,000 | $ | 7.49 |
NWR | 01/03/2008 | Swap | 01/10 – 03/10 | 1,500 | $ | 7.50 |
AECO | 01/03/2008 | Swap | 11/09 – 03/10 | 1,000 | $ | 8.07 |
San Juan El Paso | 01/23/2008 | Swap | 01/10 – 03/10 | 5,000 | $ | 7.50 |
AECO | 01/23/2008 | Swap | 04/08 – 12/08 | 1,000 | $ | 6.87 |
San Juan El Paso | 02/28/2008 | Swap | 01/10 – 03/10 | 3,000 | $ | 8.55 |
AECO | 02/28/2008 | Swap | 04/08 – 10/08 | 1,000 | $ | 8.37 |
CIG | 02/28/2008 | Swap | 04/08 – 10/08 | 1,000 | $ | 7.73 |
San Juan El Paso | 04/09/2008 | Swap | 04/10 – 06/10 | 5,000 | $ | 7.26 |
San Juan El Paso | 04/30/2008 | Swap | 04/10 – 06/10 | 2,500 | $ | 7.65 |
AECO | 08/20/2008 | Swap | 04/10 – 06/10 | 1,000 | $ | 7.73 |
San Juan El Paso | 08/20/2008 | Swap | 07/10 – 09/10 | 5,000 | $ | 7.74 |
AECO | 08/20/2008 | Swap | 07/10 – 09/10 | 1,000 | $ | 7.88 |
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Crude Oil
Location | Transaction Date | Hedge Type | Term | Volume | Price |
| | | | (Bbls/month) | |
| | | | | | |
NYMEX | 01/30/2007 | Swap | Calendar 2008 | 5,000 | $ | 61.38 |
NYMEX | 02/20/2007 | Put | Calendar 2008 | 5,000 | $ | 60.00 |
NYMEX | 03/07/2007 | Swap | Calendar 2008 | 5,000 | $ | 67.34 |
NYMEX | 03/23/2007 | Swap | 01/09 – 03/09 | 5,000 | $ | 67.60 |
NYMEX | 03/26/2007 | Put | Calendar 2008 | 5,000 | $ | 63.00 |
NYMEX | 03/28/2007 | Swap | 01/09 – 03/09 | 5,000 | $ | 69.00 |
NYMEX | 04/12/2007 | Put | 01/09 – 03/09 | 5,000 | $ | 65.00 |
NYMEX | 04/26/2007 | Swap | 04/09 – 06/09 | 5,000 | $ | 70.25 |
NYMEX | 05/10/2007 | Swap | 04/09 – 06/09 | 5,000 | $ | 69.10 |
NYMEX | 05/29/2007 | Put | 04/09 – 06/09 | 5,000 | $ | 65.00 |
NYMEX | 06/22/2007 | Swap | 07/09 – 09/09 | 5,000 | $ | 72.10 |
NYMEX | 07/27/2007 | Put | 07/09 – 09/09 | 5,000 | $ | 65.00 |
NYMEX | 09/12/2007 | Swap | 07/09 – 09/09 | 5,000 | $ | 71.20 |
NYMEX | 09/12/2007 | Put | 01/09 – 03/09 | 5,000 | $ | 70.00 |
NYMEX | 09/12/2007 | Put | 04/09 – 06/09 | 5,000 | $ | 70.00 |
NYMEX | 10/29/2007 | Put | 10/09 – 12/09 | 5,000 | $ | 75.00 |
NYMEX | 10/29/2007 | Swap | 10/09 – 12/09 | 5,000 | $ | 80.75 |
NYMEX | 11/16/2007 | Put | 07/09 – 09/09 | 5,000 | $ | 75.00 |
NYMEX | 11/16/2007 | Put | 10/09 – 12/09 | 5,000 | $ | 75.00 |
NYMEX | 01/03/2008 | Put | 01/10 – 03/10 | 5,000 | $ | 80.00 |
NYMEX | 01/03/2008 | Swap | 01/10 – 03/10 | 5,000 | $ | 88.70 |
NYMEX | 01/23/2008 | Swap | 10/09 – 12/09 | 5,000 | $ | 83.10 |
NYMEX | 01/23/2008 | Swap | 01/10 – 03/10 | 5,000 | $ | 82.90 |
NYMEX | 02/28/2008 | Put | 01/10 – 03/10 | 5,000 | $ | 85.00 |
NYMEX | 04/09/2008 | Swap | 04/10 – 06/10 | 5,000 | $ | 99.60 |
NYMEX | 04/30/2008 | Put | 04/10 – 06/10 | 5,000 | $ | 85.00 |
NYMEX | 05/29/2008 | Put | 04/10 – 06/10 | 5,000 | $ | 105.00 |
NYMEX | 07/16/2008 | Swap | 04/10 – 06/10 | 5,000 | $ | 135.10 |
NYMEX | 07/16/2008 | Swap | 07/10 – 09/10 | 5,000 | $ | 134.90 |
NYMEX | 08/20/2008 | Put | 07/10 – 09/10 | 5,000 | $ | 90.00 |
NYMEX | 09/03/2008 | Put | 07/10 – 09/10 | 5,000 | $ | 90.00 |
NYMEX | 10/24/2008 | Put | 07/10 – 09/10 | 5,000 | $ | 60.00 |
NYMEX | 10/24/2008 | Put | 10/10 – 12/10 | 5,000 | $ | 60.00 |
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ITEM 4. CONTROLS AND PROCEDURES
Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) as of September 30, 2008. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.
There have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. On July 14, 2008, we acquired the assets of Aquila’s regulated electric utility in Colorado and its regulated gas utilities in Colorado, Kansas, Nebraska and Iowa (the “Acquired Businesses”). The internal controls of the Acquired Businesses are an area of focus for us. We are in the process of reviewing the internal controls of the Acquired Businesses and making any necessary changes. As permitted by the guidance set forth by the Securities and Exchange Commission, the Acquired Businesses will not be included in management’s assessment of internal control over financial reporting for the year ending December 31, 2008.
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BLACK HILLS CORPORATION
Part II – Other Information
For information regarding legal proceedings, see Note 18 in Item 8 of our 2007 Annual Report on Form 10-K and Note 14 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 14 is incorporated by reference into this item.
Except as set forth below, there have been no material changes in risk factors involving us from those previously disclosed in Item 1A. of Part I in our Annual Report on Form 10-K for the year ended December 31, 2007.
Recent events in the global financial crisis have made the credit markets less accessible and created a shortage of available credit. We may, therefore, be unable to obtain the financing needed to refinance debt, fund planned capital expenditures, or otherwise execute our operating strategy.
Our ability to execute our operating strategy is highly dependent on our having access to capital. Historically, we have addressed our liquidity needs (including funds required to make scheduled principal and interest payments, refinance debt, and fund working capital and planned capital expenditures) with operating cash flow, borrowings under credit facilities, proceeds of debt and equity offerings, and proceeds from asset sales. Our ability to access the capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, changes in the federal or state regulatory environment affecting energy companies, volatility in electricity or natural gas prices, and general economic and market conditions.
Recent financial distress within the global economy has caused significant disruption in the credit markets. Among other things, long-term interest rates on debt securities have increased significantly and the volume of equity and debt security issuances has decreased. Recent actions taken by the United States government, the Federal Reserve and other governmental and regulatory bodies may be insufficient to stabilize these markets. The longer such conditions persist, the more significant the implications become for the Company, including the potential that adequate capital is not available (or available on reasonable commercial terms) for us to refinance the $383 million borrowing on the Acquisition Facility or to replace our uncommitted $300 million Enserco facility with a committed credit line. If we are unable to (i) timely refinance the $383 million borrowing or extend its maturity date or (ii) replace the existing uncommitted Enserco facility with a committed credit line, or both, we could be required to consider additional measures to conserve or raise capital. Among other things, alternatives could include deferring portions of our planned capital expenditure program, selling assets, issuing equity, reducing or eliminating our dividend, or curtailing certain business activities, including our marketing operations. Moreover, if we cannot complete capital conservation or capital raising alternatives at sufficient levels on a timely basis, we may not be able to repay all or a portion of the $383 million borrowing that must be repaid on February 5, 2009. In addition, we have in place forward starting interest rate swaps associated with the anticipated long-term debt issuance. If the anticipated long-term debt issuance does not occur as planned, the accounting treatment of the interest rate swaps may be impacted. The failure to consummate these anticipated refinancings, and any actions taken in lieu of such refinancings, could have a material adverse effect on our results of operations, cash flows and financial condition.
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In addition, given that the Company is a holding company and that our utility assets are owned by our subsidiaries, if we are unable to adequately access the credit markets, we could be required to take additional measures designed to ensure that our utility subsidiaries are adequately capitalized to provide safe and reliable service. These alternatives would be evaluated in the context of market conditions then-prevailing, prudent financial management, and any applicable regulatory requirements.
Recent events in the global financial crisis have also increased our counterparty credit risk.
As a consequence of the global financial crisis, the creditworthiness of numerous contractual counterparties (particularly financial institutions) has deteriorated. As the creditworthiness of our counterparties deteriorates, we face increased exposure to counterparty credit default. For example, as a result of the Lehman bankruptcy filing, we have a pre-tax exposure of $0.4 million to a Lehman entity if we are not able to setoff certain financial and physical natural gas transactions we have with the Lehman entity.
We have established guidelines, controls, and limits to manage and mitigate credit risk. For our energy marketing, production and generation activities, we seek to mitigate our credit risk by conducting a majority of our business with investment grade companies, setting tenor and credit limits commensurate with counterparty financial strength, obtaining netting agreements, and securing our credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit and other security agreements. Although we aggressively monitor and evaluate changes in our counterparties’ credit status and adjust the credit limits based upon changes in the customer’s current creditworthiness, there are no assurances that our credit guidelines, controls, and limits will protect us from increasing counterparty credit risk under today’s stressed financial conditions. To the extent the financial crisis causes our credit exposure to contractual counterparties to increase materially, such increased exposure could have a material adverse effect on our results of operations, cash flows and financial condition.
National and regional economic conditions may cause increased late payments and uncollectible accounts, which would reduce earnings and cash flows.
Recent concerns over inflation, energy costs, the availability and cost of credit, and increased unemployment have contributed to an economic slowdown and fears of recession. These factors could lead to an increase in late payments from utility customers and uncollectible accounts could increase, which could materially reduce our earnings and cash flows.
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Our credit ratings could be lowered below investment grade in the future. If this were to occur, it could impact our access to capital, our cost of capital and our other operating costs.
Our issuer credit rating is “Baa3”, with a stable outlook by Moody’s and “BBB-”, with a stable outlook by S&P. Although we believe the IPP Transaction and Aquila Transaction have strengthened our financial profile and creditworthiness, we cannot provide assurances that our credit ratings will not be lowered. If our credit ratings are lowered, it could impair our ability to refinance or repay our existing debt (including debt incurred to fund part of the Aquila purchase price) and to complete new financings on acceptable terms, if at all. A downgrade could also result in counterparties requiring us to post additional collateral under existing or new contracts or trades. In addition, a ratings downgrade would increase our interest expense under some of our existing debt obligations, including borrowings under our credit facilities.
Regulatory commissions may refuse to approve some or all of the utility rate increases we have requested or may request in the future, or may determine that amounts passed through to customers were not prudently incurred and, therefore, recoverable.
Our regulated electricity and natural gas operations are subject to cost-of-service regulation and earnings oversight. This regulatory treatment does not provide any assurance as to achievement of earnings levels. Our rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the state public utility commissions will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.
To some degree, each of our gas and electric utilities in Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota, and Wyoming is permitted to recover certain costs (such as increased fuel and purchased power costs, as applicable) without having to file a rate case. To the extent we pass through such costs to ratepayers and a state public utility commission subsequently determines that such costs should not have been paid by ratepayers, we may be required to refund such costs to ratepayers. Any such costs not recovered through rates could negatively affect our revenues.
Our operating results can be adversely affected by milder weather.
Our utility businesses are seasonal businesses and weather patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating, and demand for natural gas is extremely sensitive to winter weather effects on space heating requirements. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating seasons. Accordingly, our utility operations have historically generated less revenues and income when weather conditions are cooler in the summer and warmer in the winter. We expect that unusually mild summers and winters could have an adverse effect on our financial condition and results of operations.
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We may not be able to effectively integrate the utility operations acquired from Aquila into our existing businesses and operations, or achieve the anticipated results.
We expect our recent acquisition of Aquila properties to produce various benefits. Achieving the anticipated benefits of the acquisition is subject to a number of uncertainties, such as pending and future rate cases and operational and financial synergies. We cannot provide assurances that the businesses we acquired from Aquila will be integrated in an efficient and effective manner, or that they will be profitable after our integration efforts have been completed.
Our energy marketing and utility operations rely on storage and transportation assets owned by third parties to satisfy their obligations.
Our energy marketing operations involve contracts to buy and sell natural gas, crude oil, and other commodities, many of which are settled by physical delivery. We depend on pipelines and other storage and transportation facilities owned by third parties to satisfy our delivery obligations under these contracts. Our gas utility businesses also rely on pipeline companies and other owners of gas storage facilities to deliver natural gas to ratepayers and to hedge commodity costs. If storage capacity is inadequate or transportation is disrupted, our ability to satisfy our obligations may be hindered. As a result, we may be responsible for damages incurred by our counterparties, such as the additional cost of acquiring alternative supply at then-current market rates, or for penalties imposed by state regulatory authorities.
We rely on cash distributions from our subsidiaries to make and maintain dividends and debt payments. Our subsidiaries may not be able or permitted to make dividend payments or loan funds to us.
We are a holding company. Our investments in our subsidiaries are our primary assets. Our operating cash flow and ability to service our indebtedness depend on the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of dividends or advances. Our subsidiaries are separate legal entities that have no obligation to make any funds available for that purpose, whether by dividends or otherwise. In addition, each subsidiary’s ability to pay dividends to us depends on any applicable contractual or regulatory restrictions that may include requirements to maintain minimum levels of cash, working capital or debt service funds.
Our utility operations are regulated by state utility commissions in Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota, and Wyoming. In connection with the Aquila Transaction, the settlement agreements or acquisition orders approved by the CPUC, IUB, KCC, and NPSC provide that, among other things, (i) our utilities in those jurisdictions cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40 percent of their total capitalization; (ii) neither Black Hills Utility Holdings nor its utility subsidiaries can extend credit to us except in the ordinary course of business and upon reasonable terms consistent with market terms. In addition to the restrictions described above, each state in which we conduct utility operations imposes restrictions on affiliate transactions, including intercompany loans. If our utility subsidiaries are unable to pay dividends or advance funds to us as a result of these conditions, or if the ability of our utility subsidiaries to make dividends or advance funds to us is further restricted, it could materially and adversely affect our ability to meet our financial obligations or pay dividends to our shareholders.
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Federal and state laws concerning climate change, including emission reduction mandates, and renewable energy portfolio standards may increase our electric generation costs materially and could render some of our electric generating units uneconomical to operate and maintain.
We own regulated and unregulated coal-fired power plants in Colorado, South Dakota, and Wyoming, and we are constructing another coal-fired power plant in Wyoming. Air emissions of coal-fired power plants are subject to federal and state regulation. Recent changes in federal and state laws governing air emissions from coal-burning power plants will result in more stringent emission limitations. As the issue of climate change, particularly with respect to CO2 emissions by coal-fired power plants, receives increased attention, further emission limitations could be imposed. To the extent our coal-fired power plants are included in rate base, we will attempt to recover costs associated with complying with emission standards; however, there can be no assurance that we will be permitted to recover such compliance costs in customer rates. Nor can we provide assurance that the emission compliance costs of our non-regulated coal-fired power plants will be recoverable from utility and other purchasers of the power generated by our non-regulated power plants. In addition, future changes in environmental regulations governing air pollutants could render some of our electric generating units more expensive or uneconomical to operate and maintain.
We own electric utilities that serve customers in Colorado, Montana, South Dakota, and Wyoming. To varying degrees, Colorado and Montana have each adopted renewable portfolio standards that require electric utilities to source a minimum percentage of the power delivered to customers by a certain date in the future. These renewable energy portfolio standards have increased the power supply costs of our electric operations. If these states increase their renewable energy portfolio standards, or if similar standards are imposed by the other states in which we operate electric utilities, our power supply costs will further increase (and could increase materially). Although we will seek to recover these higher costs in rates, we can provide no assurance that we will be able to fully recover such costs.
We have recorded a substantial amount of goodwill associated with our recently completed acquisition. Any significant impairment of our goodwill would cause a decrease in our assets and a reduction in our net income and shareholders’ equity.
We had approximately $401 million of goodwill recorded on our consolidated balance sheet as of September 30, 2008. A substantial portion of the goodwill is related to our recently completed acquisition within our Utilities Group. If we make changes in our business strategy or if market or other conditions adversely affect operations in any of these businesses, we may be forced to record an impairment charge, which would lead to decreased assets and a reduction in net income. Goodwill is tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred. If the testing performed indicates that impairment has occurred, we are required to record an impairment charge for the difference between the carrying value of the goodwill and the implied fair value of the goodwill in the period the determination is made. The testing of goodwill for impairment requires us to make significant estimates about our future performance and cash flows, as well as other assumptions. These estimates can be affected by numerous factors, including changes in economic, regulatory, industry or market conditions, changes in business operations, future business operating performance, changes in competition or changes in technologies. Any changes in key assumptions, or actual performance compared with key assumptions, about our business and its future prospects or other assumptions could affect the fair value of one or more business segments, which may result in an impairment charge.
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A sustained decline in our common stock price below book value may result in goodwill impairments that could adversely affect our results of operations and financial position, and could, under current market conditions inhibit our access to capital and could result in a downgrade to our credit ratings.
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds |
Issuer Purchases of Equity Securities
| | | | Maximum |
| | | Total | Number (or |
| | | Number | Approximate |
| | | of Shares | Dollar |
| Total | | Purchased as | Value) of Shares |
| Number | | Part of Publicly | That May Yet Be |
| of | Average | Announced | Purchased Under |
| Shares | Price Paid | Plans | the Plans |
Period | Purchased | per Share | or Programs | or Programs |
| | | | | | |
July 1, 2008 – | | | | | | |
July 31, 2008 | 106 (1) | $ | 35.69 | — | | — |
| | | | | | |
August 1, 2008 – | | | | | | |
August 31, 2008 | 155 | $ | 32.87 | — | | — |
| | | | | | |
September 1, 2008 – | | | | | | |
September 30, 2008 | 36 | $ | 34.30 | — | | — |
| | | | | | |
Total | 297 | $ | 34.05 | — | | — |
__________________________
| (1) | Shares were acquired from certain officers and key employees under the share withholding provisions of the Omnibus Incentive Plan for the payment of taxes associated with the vesting of shares of Restricted Stock and the exercise of stock options. |
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Item 6. | Exhibits | |
| | |
| Exhibit 31.1 | Certification pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002. |
| | |
| Exhibit 31.2 | Certification pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002. |
| | |
| Exhibit 32.1 | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002. |
| | |
| Exhibit 32.2 | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002. |
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BLACK HILLS CORPORATION
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| BLACK HILLS CORPORATION |
| |
| |
| /s/ David R. Emery |
| David R. Emery, Chairman, President and |
| Chief Executive Officer |
| |
| |
| /s/ Anthony S. Cleberg |
| Anthony S. Cleberg, Executive Vice President |
| and Chief Financial Officer |
| |
| |
Dated: November 10, 2008 | |
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EXHIBIT INDEX
Exhibit Number | Description |
| |
Exhibit 31.1 | Certification pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002. |
| |
Exhibit 31.2 | Certification pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002. |
| |
Exhibit 32.1 | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002. |
| |
Exhibit 32.2 | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002. |
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