UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2005
- OR -
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
For the transition period from _______________ to _________________
Commission
Name of Registrants, State of Incorporation,
I.R.S. Employer
File Number
Address and Telephone Number
Identification No.
333-32170
PNM Resources, Inc.
85-0468296
(A New Mexico Corporation)
Alvarado Square
Albuquerque, New Mexico 87158
(505) 241-2700
1-6986
Public Service Company of New Mexico
85-0019030
2-97230
Texas-New Mexico Power Company
75-0204070
(A Texas Corporation)
4100 International Plaza,
P.O. Box 2943
Fort Worth, Texas 76113
(817) 731-0099
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 (the "Exchange Act") during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. YES X NO
Indicate by check mark whether each Registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).
PNM Resources, Inc. ("PNMR") YES X NO Public Service Company of New Mexico ("PNM") YES NO X Texas-New Mexico Power Company ("TNMP") YES NO X
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) YES NO X
As of October 31, 2005, 68,763,951 shares of common stock, no par value per share, of
PNMR were outstanding.
The total number of shares of Common Stock of PNM outstanding as of
October 31, 2005 was 39,117,799 all held by PNMR.
The total number of shares of Common Stock of TNMP outstanding as of
October 31, 2005 was 9,615 all held indirectly by PNMR.
This Form 10-Q represents separate filings by PNMR, PNM and TNMP. Information herein relating to an individual registrant is filed by that registrant on its own behalf. PNM makes no representations as to the information relating to PNMR and its subsidiaries other than PNM. TNMP makes no representations as to the information relating to PNMR and its subsidiaries other than TNMP. When this Form 10-Q is incorporated by reference into any filing with the SEC made by PNM or TNMP, the portions of this Form 10-Q that relate to PNMR and its subsidiaries other than PNM or TNMP, respectively are not incorporated by reference therein. On June 6, 2005, PNMR completed its acquisition of TNP Enterprises, Inc. and Subsidiaries. See Note 2 - "TNP Acquisition," in the Notes to Consolidated Financial Statements under Part I, Item 1, of this report for further information. Commencing with the Form 10-Q for the quarter ended June 30, 2005, TNMP was included in the filing of PNMR and PNM.
ii
PNM RESOURCES, INC. AND SUBSIDIARIES PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARY TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
INDEX
Page No.
GLOSSARY
1
PART I. FINANCIAL INFORMATION:
ITEM 1. FINANCIAL STATEMENTS (Unaudited)
PNM Resources, Inc. and Subsidiaries
Consolidated Statements of Earnings
Three and Nine Months Ended September 30, 2005 and 2004
4
Consolidated Balance Sheets
September 30, 2005 and December 31, 2004
5
Consolidated Statements of Cash Flows
Nine Months Ended September 30, 2005 and 2004
7
Consolidated Statements of Comprehensive Income
9
Public Service Company of New Mexico and Subsidiary
10
11
13
15
Texas-New Mexico Power Company and Subsidiaries
16
18
20
Consolidated Statements of Comprehensive Income (Loss)
22
Notes to the Consolidated Financial Statements
24
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
88
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK
167
ITEM 4. CONTROLS AND PROCEDURES
iii
PART II. OTHER INFORMATION:
ITEM 1. LEGAL PROCEEDINGS
ITEM 5. OTHER INFORMATION
168
ITEM 6. EXHIBITS
169
Signature
171
iv
Afton...................................
Afton Generating Station
ALJ......................................
Administrative Law Judge
APB.....................................
Accounting Principles Board
APS.....................................
Arizona Public Service Company
ARO....................................
Asset Retirement Obligation
AR Securitization...............
Accounts Receivable Securitization
BLM.....................................
U.S. Department of the Interior Bureau of Land Management
Board...................................
Board of Directors
BTU.....................................
British Thermal Unit
Cal PX.................................
California Power Exchange
Cal ISO................................
California Independent System Operator
Cascade...............................
Cascade Investment, LLC
CCN....................................
Certificate of Public Convenience and Necessity
Congress.............................
United States Congress
Constellation.......................
Constellation Energy Commodities Group, Inc.
CPUC..................................
California Public Utilities Commission
Decatherm..........................
1,000,000 BTUs
Delta....................................
Delta-Person Limited Partnership
DOJ.....................................
United States Department of Justice
EaR......................................
Earnings at Risk
EIP.......................................
Eastern Interconnection Project
EITF.....................................
Emerging Issues Task Force
EPE......................................
El Paso Electric Company
EPA.....................................
United States Environmental Protection Agency
ERCOT................................
Electric Reliability Council of Texas
FASB...................................
Financial Accounting Standards Board
FCPSP.................................
First Choice Power Special Purpose, L.P.
FERC...................................
Federal Energy Regulatory Commission
First Choice.........................
First Choice Power, L. P. and Subsidiaries
FIP.......................................
Federal Implementation Plan
Four Corners.......................
Four Corners Power Plant
GAAP..................................
Generally Accepted Accounting Principles in the United
States of America
Gathering Company..........
Sunterra Gas Gathering Company, a wholly‑owned
subsidiary of PNM Resources, Inc.
GCT.....................................
Grand Canyon Trust
Global Electric Agreement.
Signed by PNMR and other parties in 2003; provided for a five-year rate path for New Mexico jurisdictional customers beginning in September 2003
Great Southwestern...........
Great Southwestern Construction, Inc.
IBLA....................................
IRS.......................................
Interior Board of Land Appeals
United States Internal Revenue Service
Laurel Hill...........................
Laurel Hill Capital Partners
LIBOR.................................
London Interbank Offered Rate
Lordsburg...........................
Lordsburg Generating Station
Luna....................................
Luna Energy Facility
MMBTUs.............................
Million British Thermal Units
Moody's...............................
Moody's Investor Services, Inc.
MW.....................................
Megawatt
MWh...................................
Megawatt Hour
Navajo Acts........................
Navajo Nation Air Pollution Prevention and Control Act, the
Navajo Nation Safe Drinking Water Act, and the Navajo
Nation Pesticide Act
Ninth Circuit......................
United States Court of Appeals for the Ninth Circuit
NMED.................................
New Mexico Environment Department
NMPRC...............................
New Mexico Public Regulation Commission, successor to the
New Mexico Public Utility Commission
NNHPD..............................
Navajo Nation Historic Preservation Department
NRC....................................
United States Nuclear Regulatory Commission
NSPS...................................
New Source Performance Standards
NSR.....................................
New Source Review
OATT..................................
Open Access Transmission Tariff
O&M...................................
Operations and Maintenance Expense
PGAC..................................
Purchased Gas Adjustment Clause
PG&E..................................
Pacific Gas and Electric Co.
PNM....................................
PNMR.................................
PPA.....................................
Power Purchase Agreement
PSA.....................................
Power Supply Agreement
PSD.....................................
Prevention of Significant Deterioration
Processing Company..........
Sunterra Gas Processing Company, a wholly‑owned
PUCT..................................
Public Utility Commission of Texas
PUHCA...............................
The Public Utility Holding Company Act of 1935
PURPA................................
Public Utility Regulatory Policy Act of 1978
PVNGS................................
Palo Verde Nuclear Generating Station
Reeves.................................
Reeves Generating Station
REP......................................
Retail Electricity Provider
Restructuring Act...............
New Mexico Electric Utility Industry Restructuring Act of 1999, as amended
RMC....................................
Risk Management Committee
RMRR..................................
Routine Maintenance, Repair or Replacement
RTO.....................................
Regional Transmission Organization
SCE......................................
Southern California Edison Company
SDG&E................................
San Diego Gas and Electric Company
SEC......................................
United States Securities and Exchange Commission
Senate Bill 7........................
Legislation that established retail competition in Texas
SESCO.................................
San Angelo Electric Service Company
SFAS...................................
Statement of Financial Accounting Standards
SJCC....................................
San Juan Coal Company
SJGS.....................................
San Juan Generating Station
SO2......................................
Sulfur Dioxide
2
S&P.....................................
Standard and Poor's Ratings Services
SW Acquisition...................
SW Acquisition, L.P.
TCEQ..................................
Texas Commission on Environmental Quality
TECA..................................
Texas Electric Choice Act (also known as Senate Bill 7)
TNMP..................................
Texas‑New Mexico Power Company and Subsidiaries
TNP.....................................
TNP Enterprises, Inc. and Subsidiaries
Throughput........................
Volumes of gas delivered, whether or not owned by the
Company
USBR...................................
United States Bureau of Reclamation
USFS....................................
United States Forest Service
VaR.....................................
Value at Risk
Wood River.........................
Wood River Partners, L.P.
WSPP..................................
Western Systems Power Pool
3
ITEM 1. FINANCIAL STATEMENTS
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EARNINGS
(Unaudited)
Three Months Ended
Nine Months Ended
September 30,
2005
2004
(In thousands, except per share amounts)
Operating Revenues:
Electric
$ 518,529
$ 313,147
$1,103,648
$ 863,783
Gas
78,258
73,530
325,752
330,290
Other
330
178
884
557
Total operating revenues
597,117
386,855
1,430,284
1,194,630
Operating Expenses:
Cost of energy sold
362,863
226,849
848,532
703,862
Administrative and general
59,961
37,537
153,457
120,486
Energy production costs
36,526
33,735
112,364
107,977
Depreciation and amortization
36,847
21,802
96,859
74,370
Transmission and distribution costs
21,179
14,755
50,292
44,397
Taxes, other than income taxes
17,184
8,178
36,626
25,924
Income taxes
12,246
11,784
24,776
29,601
Total operating expenses
546,806
354,640
1,322,906
1,106,617
Operating income
50,311
32,215
107,378
88,013
Other Income and Deductions:
Interest income
10,760
9,270
31,682
28,035
Other income
5,433
1,513
11,777
4,926
Carrying charges on regulatory assets
1,910
-
2,435
Other deductions
(7,557)
(236)
(17,567)
(4,222)
Other income taxes
(3,693)
(2,918)
(9,747)
(9,104)
Net other income and deductions
6,853
7,629
18,580
19,635
Interest Charges
28,145
12,280
62,689
38,164
Preferred Stock Dividend
Requirements
536
147
2,736
440
Net Earnings
$ 28,483
$ 27,417
$ 60,533
$ 69,044
Net Earnings per Common Share:
Basic
$ 0.41
$ 0.45
$ 0.93
$ 1.14
Diluted
$ 0.92
$ 1.13
Dividends Declared per Common Share
$ 0.400
$ 0.160
$ 0.585
$ 0.560
The accompanying notes, as they relate to PNMR, are an integral part of these financial statements.
CONSOLIDATED BALANCE SHEETS
December 31,
(In thousands)
ASSETS
Utility Plant:
Electric plant in service
$3,269,524
$2,488,961
Gas plant in service
699,294
680,487
Common plant in service and plant held for future use
156,387
140,818
4,125,205
3,310,266
Less accumulated depreciation and amortization
1,346,557
1,135,510
2,778,648
2,174,756
Construction work in progress
155,042
124,381
Nuclear fuel, net of accumulated amortization of $17,669 and $16,448
28,919
25,449
Net utility plant
2,962,609
2,324,586
Other Property and Investments:
Investment in lessor notes
287,020
308,680
Other investments
162,005
139,848
Non-utility property, net of accumulated depreciation of $6 and $1,773
4,815
1,437
Total other property and investments
453,840
449,965
Current Assets:
Cash and cash equivalents
144,799
17,195
Special deposits
2,933
Accounts receivable, net of allowance for uncollectible accounts
of $4,077 and $1,329
119,258
96,600
Unbilled revenues
110,983
104,708
Other receivables
54,091
48,393
Inventories
45,730
41,352
Regulatory assets
14,147
3,339
Other current assets
99,218
51,967
Total current assets
591,159
363,554
Deferred charges:
427,090
217,196
Prepaid pension cost
90,417
87,336
Goodwill
492,693
Other intangible assets
62,718
Other deferred charges
56,033
44,998
Total deferred charges
1,128,951
349,530
$5,136,559
$3,487,635
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stockholders' equity:
Common stock outstanding (no par value)
$ 798,638
$ 638,826
Accumulated other comprehensive loss, net of tax
(68,892)
(89,813)
Retained earnings
571,678
550,566
Total common stockholders' equity
1,301,424
1,099,579
Cumulative preferred stock of subsidiary without mandatory redemption
($100 par value)
11,529
Long-term debt
1,647,077
987,823
Total capitalization
2,960,030
2,098,931
Current Liabilities:
Short-term debt
474,699
94,700
Accounts payable
157,286
117,645
Accrued interest and taxes
47,384
15,796
Other current liabilities
214,641
128,476
Total current liabilities
894,010
356,617
Deferred Credits:
Accumulated deferred income taxes
417,590
284,528
Accumulated deferred investment tax credits
34,776
35,360
Regulatory liabilities
377,899
327,419
Asset retirement obligations
50,446
50,361
Additional minimum pension liability
164,801
Accrued pension liability
3,825
Accrued postretirement benefit cost
20,816
16,102
Other deferred credits
212,366
153,516
Total deferred credits
1,282,519
1,032,087
Commitments and Contingencies (see Note 8)
6
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash Flows From Operating Activities:
Net earnings
Adjustments to reconcile net earnings to net cash flows
from operating activities:
112,000
96,837
Allowance for equity funds used during construction
(1,784)
(802)
Accumulated deferred income tax
17,330
2,056
Net unrealized (gains) losses on trading and investment contracts
380
(1,343)
358
Changes in certain assets and liabilities:
Accounts receivable
10,236
9,936
27,499
10,704
Accrued post-retirement benefit costs
(2,574)
(5,101)
Deferred charges
(10,326)
(2,893)
Other assets
(25,571)
17,942
(3,724)
(20,083)
Accrued taxes
46,899
47,864
Accrued interest
(6,857)
1,434
Deferred credits
(15,482)
(3,132)
Other liabilities
(38,309)
(9,830)
Net cash flows from operating activities
170,608
212,633
Cash Flows From Investing Activities:
Utility plant additions
(128,578)
(83,880)
Nuclear fuel additions
(10,349)
(5,820)
Utility plant additions related to allowance for borrowed funds
used during construction and capitalized interest
(2,176)
(2,251)
Return of principal of PVNGS lessor notes
21,091
20,292
Cash acquired from purchase of TNP, net of cash paid
34,531
1,039
(8,207)
Net cash flows from investing activities
(84,442)
(79,866)
Cash Flows From Financing Activities:
Short-term debt borrowings (repayments), net
380,000
(98,742)
Long-term debt borrowings
239,832
Long-term debt repayments
(399,626)
Issuance of common stock
101,231
Redemption of TNP preferred stock
(224,564)
Exercise of employee stock options
(16,064)
(9,578)
Dividends paid
(39,583)
(29,031)
212
490
Net cash flows generated (used) by financing activities
41,438
(136,861)
Increase (decrease) in cash and cash equivalents
127,604
(4,094)
Beginning of period
12,694
End of period
$144,799
$ 8,600
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest
$ 55,396
$ 33,942
Income taxes (refunded), net
$(16,176)
$ (5,508)
Supplemental schedule of noncash investing and financing activities:
PNMR purchased all of the outstanding common shares of TNP for $107.6 million in cash
and $87.4 million in PNMR common stock. In conjunction with the acquisition, liabilities were
assumed as follows:
Fair value of assets acquired
$1,494,744
Cash paid for TNP common shares
(107,602)
PNMR common stock exchanged for TNP common stock
(87,392)
Liabilities assumed
$1,299,750
8
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Other Comprehensive Income, net of tax:
Unrealized gain (loss) on securities:
Unrealized holding gains (losses)
during the period, net of income
tax (expense) benefit of $(297),
$(205), $(1,792) and $(477)
452
313
2,733
728
Reclassification adjustment for
amounts included in net income,
net of income tax (expense)
benefit of $64, $319,
$1,819 and $701
(97)
(487)
(2,775)
(1,069)
adjustment, net of income tax expense
of $(12)
19
Mark-to-market adjustment for
certain derivative transactions:
Change in fair market value of
designated cash flow hedges,
benefit of $(9,116), $290,
17,162
(442)
22,004
3,222
$(12,189) and $(2,112)
Reclassification for amounts in net
income, net of income tax
(expense) benefit of $669, $329
$682 and $261
(1,021)
(502)
(1,041)
(399)
Total Other Comprehensive Income (Loss)
16,496
(1,118)
20,921
2,501
Total Comprehensive Income
$ 44,979
$ 26,299
$ 81,454
$ 71,545
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARY
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
$ 325,274
$ 857,722
403,532
386,677
1,183,474
1,194,073
249,660
226,811
703,776
703,751
45,695
37,056
128,102
121,075
36,484
27,406
21,157
83,315
72,597
15,532
43,546
7,913
7,523
23,664
23,805
2,433
12,074
17,458
30,095
385,123
353,111
1,112,225
1,103,697
18,409
33,566
71,249
90,376
9,697
9,230
28,000
27,746
3,963
2,028
9,222
5,297
(2,677)
(1,225)
(9,704)
(2,816)
(3,987)
(2,715)
(9,989)
(9,693)
6,996
7,318
17,529
20,534
14,139
13,189
40,896
39,774
11,266
27,695
47,882
71,136
132
396
Net Earnings Available for
Common Stock
$ 11,134
$ 27,548
$ 47,486
$ 70,696
The accompanying notes, as they related to PNM, are an integral part of these financial statements.
$2,541,812
98,797
97,369
3,339,903
3,266,817
1,185,966
1,125,444
2,153,937
2,141,373
101,510
110,406
2,284,366
2,277,228
151,404
116,134
Non-utility property
966
439,390
425,780
12,855
16,448
247
of $1,353 and $1,329
78,898
74,529
46,123
45,717
44,209
41,246
50,849
39,933
321,857
347,991
281,360
39,217
38,199
410,994
342,731
$3,456,607
$3,393,730
The accompanying notes, as they relate to PNM, are an integral part of these financial statements.
Common stockholder's equity:
Common stock outstanding ($5 par value)
$ 195,589
Paid-in-capital
556,761
(88,193)
338,934
371,455
Total common stockholder's equity
1,003,091
1,033,992
987,206
987,676
2,001,826
2,033,197
114,000
60,400
78,082
116,763
Intercompany accounts payable
22,615
38,700
46,386
28,783
155,647
91,765
416,730
336,411
286,150
278,907
33,039
338,728
14,010
150,877
151,172
1,038,051
1,024,122
12
$ 47,882
$ 71,136
99,155
95,047
(1,701)
(774)
3,433
17,703
30,179
(5,173)
(21,444)
11,899
(43,709)
(12,644)
17,603
47,622
(14,358)
(2,033)
(34,940)
(9,403)
95,010
217,102
(78,507)
(83,626)
Utility plant additions related to allowance for borrowed funds used
during construction and capitalized interest
(1,476)
(2,024)
Purchase of bond investments
(12,247)
(1,844)
(2,569)
(71,085)
(85,994)
53,600
(97,700)
(80,396)
(440)
Other financing
(422)
(240)
Change in intercompany accounts
(300)
(36,273)
Net cash flows from financing activities
(27,518)
(134,653)
Decrease in cash and cash equivalents
(3,593)
(3,545)
11,607
$12,855
$ 8,062
$45,379
$ 35,890
Income taxes paid (refunded), net
$ 3
$ (2,749)
14
Unrealized holding gains (losses) during
the period, net of income tax
(expense) benefit of $(297), $(205),
$(1,792) and $(477)
Reclassification adjustment for amounts
included in net income, net of
Income tax (expense) benefit of $64
$319, $1,819 and $701
Mark-to-market adjustment for certain
derivative transactions:
designated cash flow hedges, net of
$841, $290, $(1,771)
and $(2,112)
(1,283)
2,703
income, net of income tax (expense)
benefit of $669, $329, $682 and $261
(1,949)
1,620
$ 9,185
$ 26,430
$ 49,106
$ 73,197
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
Post-Acquisition
Pre-Acquisition
$71,441
$74,732
71,441
74,732
25,764
25,956
5,970
7,552
7,814
7,433
5,670
4,442
6,597
6,509
4,412
5,760
56,227
57,652
15,214
17,080
660
128
202
237
928
(43)
(157)
(1,050)
(436)
1,679
700
7,250
6,971
$ 9,643
$10,809
The accompanying notes, as they relate to TNMP, are an integral part of these financial statements.
For the period
June 6-
January 1-
September 30, 2005
June 6, 2005
September 30, 2004
$90,676
$ 112,820
$ 201,454
90,676
112,820
201,454
32,466
43,885
73,601
8,153
11,048
22,115
9,899
12,954
22,186
6,820
9,111
14,371
8,482
9,228
17,700
5,537
5,055
10,454
71,357
91,281
160,427
19,319
21,539
41,027
747
650
435
523
925
(1,407)
(54)
(79)
(266)
(1,364)
154
(791)
2,077
(159)
1,231
9,206
12,120
21,105
Net Earnings Before Extraordinary Item
12,190
9,260
21,153
Extraordinary item - disallowance
of stranded costs, net of taxes
(97,836)
Net Earnings (Loss)
$12,190
$ 9,260
$ (76,683)
17
$ 869,877
$ 845,900
7,014
4,261
589
877,480
850,750
292,760
276,081
584,720
574,669
531
530
Non-utility property, net of accumulated depreciation of $3 and $3
2,121
343
2,652
873
30,027
65,759
2,417
3,086
of $100 and $191
13,395
12,739
Federal income tax refund
40,483
22,912
7,133
7,576
11,142
10,083
1,249
1,505
7,526
106,730
131,186
Stranded costs
87,316
Carrying charges on stranded costs
55,797
48,130
Other regulatory assets
2,617
8,105
457,109
21,995
22,227
624,834
165,778
$1,318,936
$ 872,506
Common stock outstanding ($10 par value)
$ 96
$ 107
596,710
197,751
(1,761)
(6,795)
608,996
189,302
415,790
415,569
1,024,786
604,871
32,379
15,649
24,605
22,647
Accrued payroll and benefits
4,462
1,583
5,368
5,155
66,814
45,034
135,222
138,249
1,736
2,326
39,171
40,729
4,844
6,806
2,693
40,576
33,760
227,336
222,601
January 1-June 6,
Net earnings (loss)
$ 12,190
10,498
14,042
24,131
(59)
(60)
(336)
18,447
(1,411)
26,717
Carrying charges on deferred stranded cost
(2,435)
1,407
(928)
Disallowance of stranded costs, net of taxes
97,836
(1,371)
(344)
(3,397)
549
(106)
1,566
13,549
(3,931)
(1,015)
(5,732)
(3,998)
(17,296)
Other assets and liabilities
(1,253)
2,066
76
44,383
16,925
50,671
(12,604)
(19,270)
(32,602)
Acquisition costs
(3,742)
(67)
(73)
(325)
882
(166)
(522)
(15,531)
(19,509)
(33,449)
Long-term debt costs and repayments
(9,296)
Redemption of common stock
(62,000)
(6,000)
(15,296)
(33,148)
(2,584)
1,926
63,175
56,907
$ 30,027
$ 63,175
$ 58,833
$ 5,681
$ 12,868
$ 18,461
Income taxes paid
$ 3,241
$ 2,456
$ 3,526
21
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES
Cash flow hedges, net of tax:
Interest rate hedge, net of reclassification
adjustment net of income tax benefit
of $0, and $79
129
Total cash flow hedges
$10,938
In conjunction with the acquisition of TNP by PNMR, the interest rate hedge was fair valued and
was charged to goodwill.
$(76,683)
of $0, $1,084 and $238
1,761
387
Total Comprehensive Income (Loss)
$ 11,021
$(76,296)
In conjunction with the acquisition of TNP by PNMR, the interest rate hedge was fair valued and was
charged to goodwill.
23
PNM RESOURCES, INC. AND SUBSIDIARIESPUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARYTEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Unaudited)
(1) Accounting Policies and Responsibility for Financial Statements
In the opinion of the management of PNM Resources, Inc. and Subsidiaries ("PNMR" or the "Company"), the accompanying unaudited interim consolidated financial statements reflect all normal and recurring accruals and adjustments which are necessary to present fairly the Company's financial position at September 30, 2005 and December 31, 2004, the consolidated results of its operations and comprehensive income for the three and nine months ended September 30, 2005 and 2004 and the consolidated statements of cash flows for the nine months ended September 30, 2005 and 2004. These consolidated financial statements are unaudited, and certain information and note disclosures normally included in the Company's annual consolidated financial statements have been condensed or omitted, as permitted under the applicable rules and regulations. The Company's three primary subsidiaries are Public Service Company of New Mexico and Subsidiary ("PNM"), Texas-New Mexico Power Company and Subsidiaries ("TNMP") and First Choice Power, L.P. and Subsidiaries ("First Choice"). Readers of these financial statements should refer to PNMR's, PNM's and TNMP's audited consolidated financial statements and notes thereto for the year ended December 31, 2004 that are included in the respective Annual Reports on Form 10-K for the year ended December 31, 2004. In addition, readers should refer to PNMR's Current Report on Form 8-K filed on September 26, 2005 that conformed its presentation of segment information in the 2004 Annual Report on Form 10-K to reflect its revised segment presentation (see Note 3). The results of operations presented in the accompanying financial statements are not necessarily representative of operations for an entire year.
TNP Acquisition
As discussed in Note 2, on June 6, 2005, PNMR completed the previously announced acquisition of TNP Enterprises, Inc. ("TNP") effective at 8:00 AM Central Daylight Time. Prior to the consummation of the acquisition, TNP was a privately owned holding company based in Fort Worth, Texas. TNP's principal subsidiaries are TNMP, a regulated utility operating in Texas and New Mexico, and First Choice, a certified retail electric provider operating in Texas.
The acquisition was accounted for using the purchase method of accounting. Under this method, the purchase price was allocated to the fair market value of the assets acquired and the liabilities assumed. The excess purchase price over the fair value of the assets acquired and the liabilities assumed was allocated to goodwill at TNMP and goodwill and other intangible assets at First Choice. As a result, TNMP and First Choice have recorded purchase accounting fair value adjustments to their respective assets and liabilities, including deferred assets, regulatory assets and pension and postretirement liabilities. At the date of acquisition, the excess of the purchase price over net assets acquired was allocated preliminarily to goodwill in the amount of $482.8 million and other intangible assets in the amount of $63.1 million. During the third quarter of 2005, an adjustment of $9.9 million was recorded to goodwill and the balance in goodwill at September 30, 2005 was $492.7 million. PNMR is in the process of completing
valuations of acquired property and intangible assets; therefore, the allocation of the purchase price to the acquired net assets is subject to adjustment.
TNP's largest subsidiary, TNMP, is a regulated utility; therefore, the valuations of the majority of the assets and liabilities were determined within the context of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," and did not change significantly.
The purchase accounting entries are reflected on PNMR's financial statements as of the purchase date. PNMR "pushed down" the effects of purchase accounting to the financial statements of TNMP and First Choice. Accordingly, TNMP's post-acquisition financial statements reflect a new basis of accounting, and separate financial statements are presented for pre-acquisition and post-acquisition periods, separated by a heavy black line.
Goodwill and Other Intangible Assets
The excess purchase price over the fair value of the assets acquired and the liabilities assumed by PNMR for its June 6, 2005 acquisition of TNP was allocated to goodwill and other intangible assets. Under the provisions of SFAS No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142"), PNMR does not amortize goodwill. Certain intangible assets are amortized over their estimated useful lives. Goodwill and intangible assets are evaluated for impairment at least annually, on December 31, or more frequently if events and circumstances indicate that the goodwill or other intangible assets might be impaired.
Of the $63.1 million of acquired intangible assets, $53.2 million was assigned to the trade name "First Choice." The trade name has an indefinite useful life; therefore, no amortization will be recognized, but the asset will be evaluated for impairment each reporting period. The other $9.9 million intangible asset was assigned to the First Choice customer list. The useful life of the customer list is estimated to be approximately eight years; therefore the asset will be amortized on a straight-line basis over an eight-year period.
As part of the acquisition of TNP, PNMR determined the fair value of a First Choice contractual obligation to purchase power. In comparing the pricing terms of the contractual obligation against the forward price of electricity in the relevant market, First Choice concluded that the contract was above market. In accordance with SFAS No. 141, as amended, "Business Combinations" ("SFAS 141"), at June 6, 2005, the contract was recorded at fair value and a deferred liability of $3.8 million was recorded that will be amortized as a reduction in cost of energy over the contract life, or approximately three years. The amortization matches the difference between the forward price curve and the contractual obligation for each month in accordance with the contract as of the acquisition date.
PNMR also determined the fair value of a First Choice contractual obligation to sell power to certain commercial and industrial customers. This contractual obligation was fair valued in accordance with SFAS 141. The valuation was based on the difference between the
25
current market rates charged by First Choice for these customers compared to the contractual rate embedded in the customer agreement. As a result of the analysis, First Choice determined that its rates for these contractual customers are below market rates and at June 6, 2005, recorded a deferred liability of $3.5 million that will be amortized into revenues over the contract life, or approximately three years. The amortization matches the difference between the retail market rate and the contractual obligation for each month as of the date of acquisition.
Presentation
The Notes to Consolidated Financial Statements include disclosures for PNMR, PNM and TNMP. For discussion purposes, this report will use the term "Company" when discussing matters of common applicability to PNMR, PNM and TNMP. Discussions regarding only PNMR, PNM or TNMP will be clearly indicated as such.
PNMR was established as a holding company in 2001. On December 30, 2004, PNMR became a registered holding company under PUHCA. As a result of the requirement to register as a holding company, PNMR created PNMR Services Company, a wholly-owned services company, which began operation on January 1, 2005, subject to final approval of a services company application filed with the SEC in January 2005.
PNMR performed substantially all of the corporate activities of PNM from 2001 to 2004. These activities were billed to PNM on a cost basis and were allocated to the business units. The service functions previously performed by PNMR were assumed by PNMR Services Company effective January 1, 2005.
Until June 6, 2005, TNMP provided First Choice and TNP with corporate support services, including accounting, finance, information services, legal and human resources, under a shared services agreement with First Choice dated March 1, 2001 and a similar agreement with TNP dated June 6, 1997. These services were billed at TNMP's cost and, in return, TNP and First Choice compensated TNMP for the services provided. These agreements were in effect through June 6, 2005 when they were replaced by a new shared services arrangement with PNMR Services Company.
Effective with the close of the acquisition of TNP on June 6, 2005, all TNMP employees who were providing corporate support to TNP and First Choice became employees of PNMR Services Company. PNMR Services Company provides corporate services to all of PNMR's business units, including PNM, Avistar, Inc., TNP, TNMP and First Choice per shared services agreements. These services are billed at cost on a monthly basis and allocated to the business units.
Certain amounts in the 2004 Consolidated Financial Statements and Notes thereto for PNMR, PNM and TNMP have been reclassified to conform to the 2005 financial statement presentation. Specifically, certain amounts in the 2004 Consolidated Financial Statements and
26
Notes thereto of TNMP have been reclassified to conform to PNMR's presentation for comparability.
In addition, in the PNMR and TNMP Consolidated Statements of Cash Flows for the nine months ended September 30, 2005, PNMR and TNMP present the classification of changes in restricted cash balances as an investing activity. PNMR and TNMP presented such changes as an operating activity prior to the quarter ended June 30, 2005. In the accompanying PNMR and TNMP Consolidated Statements of Cash Flows for the nine months ended September 30, 2004, the changes in these cash balances were reclassified to be consistent with the 2005 presentation. This reclassification resulted in a $1.5 million increase to PNMR investing cash flows and a corresponding decrease to PNMR operating cash flows from the amounts previously reported. This reclassification resulted in less than a $0.1 million increase to TNMP investing cash flows and a corresponding decrease to TNMP operating cash flows from the amounts previously reported.
PNMR
Stock Based Compensation
The Company accounts for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25"). Compensation cost for stock options, if any, is measured as the excess of the quoted market price of PNMR's stock at the date of grant over the exercise price of the granted stock option. Restricted stock is recorded as compensation cost over the requisite vesting periods based on the market value on the date of grant.
27
At September 30, 2005, PNMR had three stock-based employee compensation plans. Stock options continue to be granted under only two of the plans. Had compensation expense for PNMR's stock options been recognized based on the fair value on the grant date under the methodology prescribed by SFAS No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"), the effect on PNMR's pro forma net earnings and pro forma diluted earnings per share would be as follows (in thousands, except per share data):
$28,483
$27,417
$60,533
$69,044
Deduct: Total stock-based employee
compensation expense determined
under fair value based method for all
awards, net of related tax effects
(303)
(704)
(996)
(2,111)
Pro forma net earnings
$28,180
$26,713
$59,537
$66,933
Earnings per share:
Basic - as reported
Basic - pro forma
$ 0.44
$ 1.11
Diluted - as reported
Diluted - pro forma
$ 0.91
$ 1.09
SFAS No. 123 (revised 2004), "Share Based Payment" ("SFAS 123R"), supersedes APB 25. SFAS 123R requires the recognition of compensation expense, over the requisite service period, in an amount equal to the fair value of share-based payments granted to employees. The fair value of the share-based payments, excluding liability awards, is computed at the date of grant and will not be remeasured. The fair value of liability awards will be remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. SFAS 123R applies to all transactions involving the issuance, by a company, of its own equity in exchange for goods or services. SFAS 123R does not change the accounting guidance for share-based payment transactions with parties other than employees provided in SFAS 123 as originally issued and EITF Issue No. 96-18, "Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services." SFAS 123R will be effective for PNMR beginning January 1, 2006. For options issued on or prior to December 31, 2005, PNMR expects that the effect of SFAS 123R on PNMR's results of operations will not be materially different from the pro forma amounts presented in the table above for the applicable time period. PNMR anticipates that the calculation of the fair value of any options issued after December 31, 2005
28
will not be materially different from the fair value estimated in the pro forma amounts presented in the table above.
PNM
Decommissioning Costs
Accounting for decommissioning costs for nuclear and fossil-fuel generation involves significant estimates related to costs to be incurred many years in the future after plant closure. Changes in these estimates could significantly impact the Company's financial position, results of operations and cash flows. PNM owns and leases nuclear and fossil-fuel facilities that are within and outside of its retail service areas. PNM adopted the accounting requirements of SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"), on January 1, 2003. Under SFAS 143, PNM is only required to recognize and measure decommissioning liabilities for tangible long-lived assets for which a legal obligation exists. Adoption of the statement changed the method of accounting for both nuclear generation decommissioning and fossil-fuel generation decommissioning. Nuclear decommissioning costs are based on site-specific estimates of the costs for removing all radioactive and other structures at the site. PVNGS Unit 3 is excluded from PNM's retail rates while PVNGS Units 1 and 2 are included. PNM collects a provision for ultimate decommissioning of PVNGS Units 1 and 2 in its rates and recognizes a corresponding expense and liability for these amounts. Fossil-fuel decommissioning costs are also approved by the NMPRC as a component of PNM's depreciation rates. PNM believes that it will continue to be able to collect in rates for its legal asset retirement obligations for nuclear and fossil-fuel generation activities included in the ratemaking process.
In addition, PNM has a contractual obligation with the PVNGS participants to fund separately the nuclear decommissioning cost at a level in excess of what PNM has identified as its legal asset retirement obligation under SFAS 143. The contractual funding obligation is based on a site-specific estimate prepared by a third party. PNM's most recent site-specific estimates for nuclear decommissioning costs were developed in 2004, using 2004 cost factors, and are based on prompt dismantlement decommissioning, reflecting the costs of removal discussed above, with such removal occurring shortly after operating license expiration. PNM's share of the contractual funding obligation through the end of the licensing terms is approximately $216.7 million (measured in 2004 dollars). The estimates are subject to change based on a variety of factors, including cost escalation, changes in technology applicable to nuclear decommissioning and changes in federal, state or local regulations. The operating licenses for PVNGS Units 1, 2 and 3 will expire in 2025, 2026, and 2027, respectively. PNM does not have a similar contractual funding obligation related to its fossil-fuel plants.
29
TNMP
Extraordinary Item
In the second quarter of 2004, TNMP recorded a loss of $97.8 million related to the PUCT true-up proceeding regarding TNMP's stranded costs. The purpose of the true-up proceeding was to quantify and reconcile the amount of stranded costs that TNMP may recover from its transmission and distribution customers. The PUCT decision established $128.4 million as TNMP's stranded costs and allowed TNMP to recover $87.3 million of the $266.5 million that TNMP requested for its true-up balance. This decision resulted in a loss of $155.2 million before tax ($97.8 million after tax). TNMP recorded the $97.8 million after tax loss as an extraordinary item in accordance with the requirements of SFAS No. 101, "Regulated Enterprises - Accounting for the Discontinuance of the Application of FASB Statement No. 71."
(2) TNP Acquisition
On June 6, 2005, PNMR acquired all of the outstanding common shares of TNP, including its principal subsidiaries, TNMP and First Choice. The results of TNP's operations have been included in the consolidated financial statements of PNMR from that date. PNMR acquired TNP in order to complement its existing New Mexico electric operations and to expand into the retail and wholesale markets in Texas.
The aggregate purchase price was $1,277 million, including a payment to the previous owner of $175.0 million consisting of $87.6 million of cash and common stock valued at $87.4 million. In addition, the aggregate purchase price included $1,034 million of TNP debt and preferred stock and incurred transaction and other costs of $67.7 million. The value of the 4,326,337 common shares issued was determined based on $20.20 per common share as provided for in the Stock Purchase Agreement. The purchase price was based on an estimated purchase price in accordance with the Stock Purchase Agreement, dated as of July 24, 2004 by and between PNMR and SW Acquisition. PNMR is in the process of completing valuations of acquired property and intangible assets; thus, the allocation of the purchase price is subject to adjustment and will be finalized within one year of the acquisition.
Pursuant to the Stock Purchase Agreement, PNMR provided SW Acquisition its proposed final purchase price, reflecting a reduction from the estimated purchase price of approximately $37 million. SW Acquisition has objected to PNMR's proposed final purchase price. There is a mechanism established in the Stock Purchase Agreement for resolving disputes regarding the final purchase price. However, in August 2005, SW Acquisition filed a petition against PNMR in Texas state district court, in which SW Acquisition alleged, among other things, that PNMR had breached the Stock Purchase Agreement. The petition seeks a declaration of the parties' rights and duties under the Stock Purchase Agreement, including the final purchase price, and also seeks damages in an unspecified amount. In September 2005, PNMR filed an answer to the petition generally denying SW Acquisition's claims and a counterclaim seeking damages for
30
SW Acquisition's breaches of contract including its early termination of the negotiation period provided for in the Stock Purchase Agreement and its breach of the provisions in the Stock Purchase Agreement regarding alternate dispute resolution. PNMR also filed a motion to compel arbitration consistent with the Stock Purchase Agreement and a motion for a preliminary injunction that would force SW Acquisition to choose an accountant to resolve the purchase price dispute. The court has scheduled a hearing on the motion to compel arbitration for November 2005. PNMR believes the SW Acquisition petition is without merit and intends to vigorously defend itself and otherwise protect its rights under the Stock Purchase Agreement.
The following unaudited pro forma financial information presents a summary of PNMR's consolidated results of operations for the three and nine months ended September 30, 2005 and 2004 assuming the acquisition of TNP had been completed as of January 1, 2004, including adjustments, which are based upon preliminary estimates, to reflect the allocation of the purchase price to the acquired net assets. The pro forma financial information does not include synergy savings that may result from the business combination and is not necessarily indicative of the results of operations if the acquisition had been effective as of these dates.
For the Three Months Ended
For the Nine Months Ended
Operating revenues
$ 597,117
$ 593,341
$1,654,807
$1,723,530
Operating expenses
$ 546,255
$ 526,066
$1,520,815
$1,557,614
Earnings before extraordinary item
$ 27,710
$ 50,129
$ 66,142
$ 109,080
$ 11,244
Net earnings per common share
before extraordinary item:
$ 0.40
$ 0.73
$ 0.96
$ 1.59
$ 0.71
$ 0.95
$ 1.57
Net earnings per common share:
$ 0.16
(3) Segment Information
PNMR is an investor-owned holding company of energy and energy related businesses. Its three primary subsidiaries are PNM, TNMP and First Choice. PNM is an integrated public utility with regulated operations primarily engaged in the generation, transmission and distribution of electricity, transmission, distribution and sale of natural gas within New Mexico, and unregulated operations primarily focused on the sale and marketing of electricity in the Western United States. TNMP is a regulated utility operating in Texas and New Mexico. In
31
Texas, TNMP provides regulated transmission and distribution services. In New Mexico, TNMP provides integrated electric services that include the transmission, distribution, purchase and sale of electricity to its New Mexico customers. First Choice is a competitive retail electric provider operating in Texas. In addition, PNMR provides energy and technology related services through its wholly owned subsidiary, Avistar, Inc.
The following segment presentation is based on the methodology that the Company's management uses for making operating decisions and assessing performance of its various business activities. The following presentation reports operating results without regard to the effect of accounting or regulatory changes and similar non-recurring items not related to normal operations. A reconciliation from the segment presentation to the GAAP financial statements is provided.
In conjunction with the TNP acquisition, management changed its business segment reporting. As it currently operates, PNMR's principal businesses include regulated operations and unregulated operations. Regulated Operations include the segments PNM Electric, TNMP Electric and PNM Gas. Unregulated Operations include the segments PNM Wholesale and First Choice. Company management has combined two segments previously reported separately, Transmission and Electric, to form one reportable segment, PNM Electric. The prior year amounts have been conformed to reflect this change for comparison purposes. As required by SEC regulations, PNMR filed a Current Report on Form 8-K on September 26, 2005 that conformed its presentation of segment information in the 2004 Annual Report on Form 10-K to reflect the revised segment presentation.
REGULATED OPERATIONS
PNM Electric
PNM Electric is an integrated electric utility that consists of the generation, transmission and distribution of electricity for retail electric customers in New Mexico and the sale of transmission to third parties as well as to PNM Wholesale and TNMP. PNM Electric provides retail electric service to a large area of north central New Mexico, including the cities of Albuquerque and Santa Fe, and certain other areas of New Mexico. Customer rates for retail electric service are set by the NMPRC based on the provisions of the Global Electric Agreement (see Note 9). PNM Electric owns or leases transmission lines, interconnected with other utilities in New Mexico, and south and east into Texas, west into Arizona, and north into Colorado and Utah.
32
TNMP Electric
TNMP Electric consists of the operations of TNMP. TNMP is a regulated utility operating in Texas and New Mexico. In Texas, TNMP provides regulated transmission and distribution services under the provisions of TECA, the legislation that established retail competition in Texas (Senate Bill 7). In New Mexico, TNMP provides integrated electricity services that include the transmission, distribution, purchase and sale of electricity to its New Mexico customers as well as transmission to third parties and to PNM. TNMP's Texas and New Mexico operations are subject to traditional cost-of-service regulation.
PNM Gas
PNM Gas distributes natural gas to most of the major communities in New Mexico, including two of New Mexico's three largest metropolitan areas, Albuquerque and Santa Fe. The customer base of PNM Gas includes both sales-service customers and transportation-service customers. PNM Gas purchases natural gas in the open market and resells it at cost to its distribution customers. As a result, increases or decreases in gas revenues resulting from wholesale gas price fluctuations do not impact PNMR's or PNM's consolidated gross margin or earnings.
UNREGULATED OPERATIONS
PNM Wholesale
PNM Wholesale consists of the generation and sale of electricity into the wholesale market based on two product lines that include long-term contracts and short-term sales. The source of these sales is supply created by selling the unused capacity of jurisdictional assets as well as the capacity of the Company's wholesale plants excluded from retail rates. Both regulated and unregulated generation is jointly dispatched in order to improve reliability, provide the most economic power to retail customers, and maximize profits on any wholesale transactions.
Long-term contracts include sales to firm-requirements and other wholesale customers with multi-year arrangements. Short-term sales generally include transactions entered into for up to two years. They also include spot market, hour ahead, day ahead, week ahead and forward market opportunities in which PNM Wholesale utilizes its asset backed strategy. Also included in short-term sales are sales of any excess generation not required to fulfill PNM Electric's retail load and contractual commitments. Short-term sales also cover the revenue credit to retail customers as specified in the Global Electric Agreement. PNM Wholesale also sells transmission services to TNMP.
In addition, adjustments related to EITF Issue 03-11, "Reporting Realized Gains and Losses on Derivative Instruments that are subject to FASB statement No. 133 and Not Held for Trading Purposes," are included in Corporate and Other. These accounting pronouncements require a net presentation of trading gains and losses and realized gains and losses for certain non-
33
trading derivatives. Management evaluates PNM Wholesale operations on a gross presentation basis due to its primarily net asset-backed marketing strategy and the importance it places on the Company's ability to repurchase and remarket previously sold capacity.
First Choice
First Choice is a certified retail electric provider operating in Texas, which allows it to provide electricity to residential, small and large commercial, industrial and institutional customers. First Choice performs all activities in Texas with Texas retail customers, including acquiring new retail customers, setting up retail accounts, handling customer inquiries and complaints, and acting as a liaison between the transmission and distribution companies and retail customers. First Choice was organized in 2000 to act as TNMP's affiliated retail electric provider, as required by TECA, the legislation that established retail competition in Texas (also known as Senate Bill 7).
CORPORATE AND OTHER
On December 30, 2004, PNMR became a registered holding company under PUHCA. As a result of the requirement to register as a holding company, PNMR created PNMR Services Company, a services company, which began operation on January 1, 2005, subject to final approval of a services company application filed with the SEC in January 2005. The comprehensive energy legislation enacted in August 2005 resulted in the repeal of PUHCA on a delayed basis. PNMR is in the process of evaluating the effects of that repeal, along with the other provisions of the legislation. (See Note 9.)
PNMR provides energy and technology related services through its wholly owned subsidiary, Avistar, Inc., and those results are included in the Corporate and Other segment.
34
PNMR Segment Information
Summarized financial information for PNMR by business segment for the three months ended September 30, 2005 is as follows (in thousands):
Regulated
Unregulated
Segments of Business
First
Corporate
Wholesale
Choice
& Other
Consolidated
2005:
Operating revenues:
$ 161,258
$ 49,373
$ 78,258
$168,384
$155,479
$(15,635)
(a)
$597,117
Intersegment revenues
1,687
22,068
429
11,471
(35,655)
Total revenues
162,945
78,687
179,855
155,479
(51,290)
Less: Cost of energy
57,958
53,512
156,024
120,751
(51,146)
Intersegment energy
Transfer
(7,205)
7,205
Gross margin
112,192
45,677
25,175
16,626
34,728
(144)
234,254
66,441
17,958
25,778
11,581
11,800
1,292
(b)
134,850
Depreciation and
amortization
17,276
5,630
3,667
480
1,980
7,998
4,476
(3,595)
(1,027)
7,826
(3,432)
(b,d)
20,477
15,429
(2,638)
2,405
14,622
Interest Income
7,103
938
1,322
612
125
income/(deductions)
1,111
2,070
(131)
376
(36)
(4,140)
(c)
(750)
(3,252)
(1,093)
(319)
(672)
(208)
1,851
Interest charges
(8,273)
(7,250)
(2,848)
(3,971)
(434)
(5,369)
(d)
(28,145)
Segment net income (loss)
$ 17,166
$ 9,816
$ (4,998)
$ (540)
$ 14,556
$ (7,517)
Total assets at
$1,811,181
$1,252,071
$634,161
$430,385
$281,693
$727,068
$ -
$ 457,109
$ 35,584
$ 492,693
Gross property additions
$ 22,627
$ 10,986
$ 9,422
$ 2,909
$ 98
$ 15,112
$ 61,154
(a) Reflects EITF 03-11 impact, under which wholesale revenues and the associated cost of energy of $16.0 million are reclassified to a net margin basis in accordance with GAAP.
(b) Includes TNP acquisition related costs of $4.6 million in operating expenses and an income tax benefit of $1.8 million in income taxes.
(c) Includes TNP debt refinancing costs of $0.4 million in other income/(deductions).
(d) Includes TNP debt refinancing costs of $0.4 million in interest charges and an income tax benefit of $0.1 million in income taxes.
35
Summarized financial information for PNMR by business segment for the three months ended September 30, 2004 is as follows (in thousands):
2004:
$ 150,961
$ 72,880
$ 184,239
$ (23,327)
$ 384,753
1,452
2,102
152,413
184,239
(23,327)
50,675
48,127
151,514
(23,467)
(9,838)
9,838
111,576
25,403
22,887
140
160,006
60,652
22,460
9,898
1,195
94,205
12,568
4,574
3,077
11,757
(1,740)
2,582
(815)
26,599
109
7,330
(1,823)
7,155
203
1,366
546
Income/(deductions)
366
331
1,130
(3,003)
(82)
(686)
853
(8,659)
(2,765)
(3,391)
2,535
(12,280)
$ 22,521
$ (2,531)
$ 4,985
$ 2,442
December 31, 2004
$1,764,032
$ 512,538
$ 430,493
$780,572
$ 3,487,635
$ 17,319
$ 7,357
$ 1,850
$ 3,695
$ 30,221
(a) Reflects EITF 03-11 impact, under which wholesale revenues and the associated cost of energy of $23.5 million are reclassified to a net margin basis in accordance with GAAP.
36
Summarized financial information for PNMR by business segment for the nine months ended September 30, 2005 is as follows (in thousands):
Electric*
Choice*
$ 431,063
$ 62,057
$325,752
$439,661
$198,510
$ (55,277)
$1,401,766
4,845
28,619
605
14,480
(20,031)
28,518
435,908
326,357
454,141
198,510
(75,308)
150,359
221,239
364,989
154,834
(75,355)
(24,740)
24,740
310,289
58,210
105,118
64,412
43,676
47
581,752
195,017
23,044
74,082
33,549
14,997
12,050
352,739
52,329
16,802
11,695
585
5,549
14,868
5,694
2,200
2,848
9,846
(10,680)
48,075
19,573
12,034
16,320
18,248
(6,872)
20,791
2,181
3,969
773
3,221
2,141
2,695
333
1,714
(51)
(12,923)
(6,091)
(9,079)
(995)
(2,250)
(259)
4,200
(25,387)
(9,206)
(8,677)
(11,974)
(462)
(6,983)
(62,689)
$ 36,541
$ 12,445
$ 4,876
$ 7,779
$ 18,249
$ (19,357)
$ 727,068
$ 63,342
$ 12,671
$ 28,143
$ 7,078
$ 144
$ 29,725
$ 141,103
(a) Reflects EITF 03-11 impact, under which wholesale revenues and the associated cost of energy of $27.6 million are reclassified to a net margin basis in accordance with GAAP.
(b) Includes TNP acquisition related costs of $9.1 million and regulatory costs associated with the NMPRC's approval of the acquisition of $2.3 million in operating expenses and an income tax benefit of $4.5 million in income taxes.
(c) Includes TNP debt refinancing costs of $2.4 million and a write-off of software costs of $4.5 million in other income/(deductions) and an income tax benefit of $1.8 million in other income taxes.
(d) Includes TNP debt refinancing costs of $4.5 million in interest charges and an income tax benefit of $2.0 million in income taxes.
* Includes results from June 6 through September 30, 2005.
37
Summarized financial information for PNMR by business segment for the nine months ended September 30, 2004 is as follows (in thousands):
$ 417,702
$ 329,226
$ 475,414
$ (33,051)
$1,189,291
4,275
1,064
5,339
421,977
475,414
(33,051)
141,547
228,925
366,887
(33,497)
(34,175)
34,175
314,605
101,365
74,352
446
490,768
191,891
72,178
33,036
298,784
45,936
14,041
10,585
3,808
20,086
2,734
8,137
(1,356)
56,692
12,412
22,594
(3,685)
21,235
1,361
4,104
1,335
701
(78)
1,085
(1,444)
264
(8,685)
(508)
(2,055)
2,144
(26,042)
(8,241)
(10,177)
6,296
(38,164)
Segment net income
$ 43,901
$ 4,946
$ 15,551
$ 4,646
$ 57,479
$ 21,346
$ 6,575
$ 6,551
$ 91,951
(a) Reflects EITF 03-11 impact, under which wholesale revenues and the associated cost of energy of $33.6 million are reclassified to a net margin basis in accordance with GAAP.
38
PNM Segment Information
Summarized financial information for PNM by business segment for the three months ended September 30, 2005 is as follows (in thousands):
$(15,965)
$ 391,935
(1,990)
11,597
(17,955)
(17,834)
(121)
153,872
1,824
105,624
833
(943)
(1,835)
334
Other income/(deductions)
(202)
1,154
256
953
(14,139)
$ (494)
$580,880
$ (4,514)
$ 30,444
(b) Includes TNP acquisition related costs of $2.5 million in operating expenses and an income tax benefit of $1.0 million in income taxes.
39
Summarized financial information for PNM by business segment for the three months ended September 30, 2004 is as follows (in thousands):
$ (23,505)
$ 384,575
(23,505)
159,866
59
93,069
(525)
(472)
506
(143)
656
1,056
1,626
(13,189)
$ 2,573
$686,667
$ 4,446
$ 30,972
40
Summarized financial information for PNM by business segment for the nine months ended September 30, 2005 is as follows (in thousands):
$(30,942)
$1,165,534
17,940
(32,932)
(32,811)
479,698
5,028
307,676
2,489
(2,458)
(5,180)
1,059
(5,066)
(878)
2,335
5,142
(40,896)
$ (1,710)
$ (8,231)
$ 90,332
(b) Includes TNP acquisition related costs of $3.6 million and regulatory costs associated with the NMPRC's approval of the acquisition of $2.3 million in operating expenses and an income tax benefit of $2.3 million in income taxes.
(c) Includes a write-off of software costs of $4.5 million in other income/(deductions) and an income tax benefit of $1.8 million in other income taxes.
41
Summarized financial information for PNM by business segment for the nine months ended September 30, 2004 is as follows (in thousands):
$(33,608)
$1,188,734
(33,608)
490,322
149
297,254
2,035
(862)
(1,322)
1,046
2,041
1,555
4,686
(39,774)
$ 6,298
$ 6,070
$ 91,470
TNMP operates in only one reportable segment; therefore tabular presentation of segment data is not required.
(4) Fair Value of Financial Instruments
PNMR and PNM
Interest Rate Management
42
The Company may enter into agreements for derivative instruments, including options and swaps, to manage risks related to changes in interest rates. At the inception of any such transaction, the Company documents relationships between the hedging instruments and the items being hedged. This documentation includes the strategy that supports executing the specific transaction. See Note 6 for details regarding interest rate swaps PNMR has entered into.
Cash Management
Until October 2005, when the program was discontinued, PNMR had a cash management program that included a preferred stock dividend capture strategy and various absolute return strategies that had the objective of achieving returns higher than that associated with passive cash management plans and with bond-like volatility. PNMR's initial investment in its cash management program was $10.0 million and an additional $2.0 million was invested in February 2005. As of September 30, 2005 and December 31, 2004, the balance, included in other current assets, for this investment, including profits and interest, was $10.1 million and $10.6 million, respectively.
PNMR determined that one of its investments under this program, Wood River, had experienced a loss in market value. At September 30, 2005, PNMR wrote down the value of its investment in Wood River to zero and incurred a loss of approximately $3.6 million for the three and nine months ended September 30, 2005.
First Choice Natural Gas Contracts
During July 2005, First Choice began entering into various gas contracts. These contracts are marked to market in accordance with GAAP. The change in mark-to-market valuation is recognized in earnings each period and is recorded in operating revenues and cost of energy, as applicable. None of these contracts settled during the third quarter of 2005. As of September 30, 2005, First Choice had a net mark-to-market asset (gain) of $1.5 million recorded in operating revenues for these contracts.
43
First Choice Energy Contracts
During July 2005, First Choice also began entering into various forward physical contracts for the purchase and sale of electricity with the intent of optimizing market opportunities. These contracts, which are derivatives, do not qualify for normal purchase and sale designation pursuant to GAAP, and are marked to market. None of these contracts settled during the third quarter of 2005. As of September 30, 2005, First Choice had a net mark-to-market liability (loss) of $0.7 million recorded in operating revenues for these contracts.
First Choice Natural Gas Hedges
First Choice also enters into natural gas transactions to hedge the variable component of certain heat-rate based power products used to serve customer load. These products are priced based on gas to power conversion rates using the spot price for natural gas . The hedges are effective in offsetting future cash flow volatility caused by increases in natural gas prices. The fair value of the natural gas hedges as of September 30, 2005, was an asset of $29.1 million, which is recorded on PNMR's balance sheet as a current asset. There was no hedge ineffectiveness on these transactions. For the three and nine months ended September 30, 2005, (after June 6, 2005) First Choice's cost of energy includes gains of $9.0 million related to the settlement of natural gas hedges.
Retail Natural Gas Contracts
The NMPRC has authorized PNM to hedge certain portions of natural gas supply contracts to protect PNM's natural gas customers from the risk of adverse price fluctuations in the natural gas market. Hedge gains and losses are recoverable through PNM's PGAC if deemed prudently incurred by the NMPRC. As a result, earnings are not affected by gains or losses generated by these instruments.
PNM purchased $2.8 million and $6.8 million of natural gas options during the third quarter and first nine months of 2005, respectively, to protect its natural gas customers from the risk of rising prices during the 2005-2006 heating season. At September 30, 2005, PNM had $6.8 million included in other current assets on its balance sheet for the purchase of gas options that essentially cap the amount PNM would pay for each volume of gas subject to the options during the winter heating season. These options will be amortized as cost of energy on PNM's income statement beginning in October 2005. PNM expects to recover its option premiums as a component of the PGAC during the months of October 2005 through February 2006. PNM does not expect to purchase additional gas options in 2005.
PNM entered into fixed-for-float financial transactions to hedge a portion of its winter gas purchase portfolio. PNM has hedged 10.9 million MMBTUs utilizing the fixed-for-float strategy for the next two winter heating seasons.
Wholesale Electricity Contracts
PNM Wholesale has entered into various forward physical contracts for the purchase and sale of electricity with the intent to optimize its net generation position. These contracts, which are derivatives, do not qualify for normal purchase and sale designation pursuant to GAAP, and are marked to market.
44
For the three months ended September 30, 2005, PNM Wholesale settled derivative forward contracts for the sale of electricity that generated $64.5 million of electric revenues by delivering 1.0 million MWh. For the three months ended September 30, 2005, PNM Wholesale settled derivative forward contracts for the purchase of electricity of $80.5 million or 1.2 million MWh to support these contractual sales and other open market sales opportunities.
For the nine months ended September 30, 2005, PNM Wholesale settled derivative forward contracts for the sale of electricity that generated $143.9 million of electric revenues by delivering 2.6 million MWh. For the nine months ended September 30, 2005, PNM Wholesale settled derivative forward contracts for the purchase of electricity of $144.7 million or 2.5 million MWh to support these contractual sales and other open market sales opportunities.
For the three months ended September 30, 2004, PNM Wholesale settled derivative forward contracts for the sale of electricity that generated $76.1 million of electric revenues by delivering 1.3 million MWh. For the three months ended September 30, 2004, PNM Wholesale settled derivative forward contracts for the purchase of electricity of $64.8 million or 1.1 million MWh to support these contractual sales and other open market sales opportunities.
For the nine months ended September 30, 2004, PNM Wholesale settled derivative forward contracts for the sale of electricity that generated $148.7 million of electric revenues by delivering 2.8 million MWh. For the nine months ended September 30, 2004, PNM Wholesale settled derivative forward contracts for the purchase of electricity of $133.1 million or 2.6 million MWh to support these contractual sales and other open market sales opportunities.
As of September 30, 2005, PNM Wholesale had open derivative forward contract positions to buy $40.6 million and to sell $59.5 million of electricity. At September 30, 2005, PNM Wholesale had a gross mark-to-market gain (asset position) on these derivative forward contracts of $12.6 million and a gross mark-to-market loss (liability position) of $12.9 million, recorded in other assets and liabilities, respectively. The change in mark-to-market valuation is recognized in earnings each period and is recorded in operating revenues and cost of energy, as applicable.
PNM Wholesale also entered into forward physical contracts for the sale of PNM's electric capacity in excess of its retail and wholesale firm requirement needs, including reserves. In addition, PNM Wholesale entered into forward physical contracts for the purchase of retail needs, including reserves, when resource shortfalls exist. PNM Wholesale generally accounts for these as normal sales and purchases as defined by SFAS 133. From time to time PNM Wholesale makes forward purchases to serve its retail needs when the cost of purchased power is less than the incremental cost of its generation. At September 30, 2005, PNM Wholesale had open forward positions classified as normal sales of electricity of $123.7 million and normal purchases of electricity of $42.9 million, which will be reflected in the financial statements upon physical delivery.
45
The operations of PNM Wholesale, including both firm commitments and other wholesale sale activities, are managed primarily through a net asset-backed strategy, whereby PNM Wholesale's aggregate net open position is covered by its own excess generation capabilities. PNM Wholesale is exposed to market risk if its generation capabilities were disrupted or if its retail load requirements were greater than anticipated. If PNM Wholesale were required to cover all or a portion of its net open contract position, it would have to meet its commitments through market purchases.
PNM Wholesale is exposed to credit risk in the event of non-performance or non-payment by counterparties of its financial and physical derivative instruments. PNM Wholesale uses a credit management process to assess and monitor the financial conditions of counterparties. PNM Wholesale's credit risk with its largest counterparty as of September 30, 2005 and December 31, 2004 was $21.3 million and $26.2 million, respectively.
Wholesale Gas Contracts
PNM Wholesale enters into various fixed-for-float price swaps to manage the price risk of certain forward sales of power. These contracts, along with the underlying power sales, are marked to market in accordance with GAAP.
As of September 30, 2005, PNM Wholesale had open derivative forward contract positions to sell $24.9 million of natural gas. At September 30, 2005, PNM Wholesale had a gross mark-to-market gain (asset position) on these derivative forward contracts of $11.6 million and a gross mark-to-market loss (liability position) of $9.6 million, recorded in other current assets and liabilities, respectively. The change in mark-to-market valuation is recognized in earnings each period and is recorded in operating revenues and cost of energy as applicable.
Normal Purchases and Sales
In the normal course of business, TNMP enters into commodity contracts, which include components for additional purchases or sales of electricity, in order to meet customer requirements. Criteria by which option-type and forward contracts for electricity can qualify for the normal purchase and sales exception has been defined by SFAS 133. In accordance with these GAAP pronouncements, management has determined that its contracts for electricity qualify for the normal purchases and sales exception. Accordingly, TNMP does not account for its electricity contracts as derivatives.
46
(5) Earnings Per Share
In accordance with SFAS No. 128, "Earnings per Share" ("SFAS 128"), dual presentation of basic and diluted earnings per share has been presented in PNMR's Consolidated Statements of Earnings. The following reconciliation illustrates the impact on the share amounts of potential common shares and the earnings per share amounts:
Basic:
Average Number of Common
Shares Outstanding
68,742
60,422
64,972
60,405
Net Earnings per Share of
Common Stock (Basic)
Diluted:
Dilutive Effect of Common Stock
Equivalents (a)
791
824
797
804
Average Common and Common
Equivalent Shares Outstanding
69,533
61,246
65,769
61,209
Net Earnings per Share of Common
Stock (Diluted)
(a) Excludes the effect of average anti-dilutive common stock equivalents related to out-of-the-money options of zero and 6,725 for the three months and 62,095 and 707,734 for the nine months ended September 30, 2005 and 2004, respectively.
(6) Capitalization
Revolving and Other Credit Facilities
In August 2005, PNMR completed arrangements to expand the size, extend the maturity and modify certain terms and conditions of its previous unsecured revolving credit facility and executed an amended and restated credit agreement (the "PNMR Facility"). The PNMR Facility expands the size of its previous revolving credit facility from $400.0 million to $600.0 million. Under the PNMR Facility, the borrowing availability of First Choice was increased from $100.0 million to $300.0 million to support First Choice's future business activities. The PNMR Facility has an expiration date of August 15, 2010 and includes two one-year extension options that are subject to approval by a majority of the lenders. At September 30, 2005, there were no outstanding borrowings under the PNMR Facility.
At September 30, 2005, PNMR also had $15.0 million in local lines of credit. There were no outstanding borrowings under the local lines of credit at September 30, 2005.
In June 2005, PNMR established a commercial paper program under which it may issue up to $400.0 million in commercial paper for up to 270 days. The commercial paper is unsecured and the proceeds are used for short-term cash management needs. The PNMR Facility serves as a backstop for the outstanding commercial paper. At September 30, 2005, there were $356.9 million of commercial paper borrowings outstanding under this program.
At September 30, 2005, First Choice had up to $300.0 million of borrowing capacity under the PNMR Facility. Any borrowings made by First Choice under this sublimit are guaranteed by PNMR. At September 30, 2005, First Choice had no borrowings outstanding under the PNMR Facility; however, First Choice had $103.9 million of letters of credit outstanding, which reduces the available capacity under the PNMR Facility. TNMP is also a borrower under the PNMR Facility, see "TNMP" detail below.
Financing Activities
PNMR has a universal shelf registration statement filed with the SEC for the issuance of debt securities and equity securities, preferred stock, purchase contracts, purchase contract units and warrants. As of September 30, 2005, PNMR had approximately $400.9 million of remaining unissued securities under this registration statement.
PNMR has entered into three fixed-to-floating interest rate swaps with an aggregate notional principal amount of $150.0 million. Under these swaps, PNMR receives a 4.40% fixed interest payment on the notional principal amount on a semi-annual basis and pays a floating rate equal to the six month LIBOR plus 58.15 basis points (0.5815%) on the notional amount
48
through September 15, 2008. The initial floating rate was 1.91% and will be reset every six months. The floating rate was reset on September 15, 2005, to 4.60%. The swap is accounted for as a fair-value hedge with a negative fair-market value (liability position) of approximately $3.2 million as of September 30, 2005.
During October 2004, PNMR entered into two forward starting floating-to-fixed rate interest rate swaps with an aggregate notional principal amount of $100.0 million. These swaps became effective August 1, 2005 and terminate November 15, 2009. Under these swaps, PNMR receives a floating rate equal to the three month LIBOR rate on the notional principal amount and pays a fixed interest rate of 3.975% on the notional principal amount on a quarterly basis. The initial floating rate was set on August 1, 2005, at 3.693% and will be reset every three months.
From November 2004 through June 30, 2005, the swaps were accounted for as a cash flow hedge against borrowings under a five-year $400.0 million PNMR revolving credit agreement dated November 15, 2004. The PNMR Facility replaced the November 2004 credit agreement in August 2005. Effective June 30, 2005, the swaps were de-designated as cash flow hedges due to a change in the underlying borrowings being hedged from the November 2004 credit agreement at the inception of the hedge to commercial paper. The mark-to-market change in the fair value of theses swaps was subsequently recognized on PNMR's income statement. At September 30, 2005, the increase in fair value related to these swaps was $2.1 million. Of this increase, $0.3 million was recorded in accumulated other comprehensive income on PNMR's balance sheet and $1.8 million was recognized in other income on PNMR's income statement for the three and nine months ended September 30, 2005.
Cascade Transaction
In October 2005, PNMR completed a private offering of 4,000,000 equity-linked securities at 6.625% to Cascade. PNMR received $100.0 million in proceeds from this transaction and there were no underwriting discounts or commissions. PNMR used the proceeds to repay short-term borrowings.
Each equity unit consists of a purchase contract and a 2.5% undivided beneficial ownership interest in one of PNMR's senior notes with a stated amount of $1,000, which corresponds to a $25.00 stated amount of PNMR's senior notes. The ownership interest in the senior notes is initially pledged to secure Cascade's obligation to purchase PNMR common stock under the related purchase contract. The senior notes are scheduled to mature in August 2010 (subject to the remarketing described below) and bear interest initially at the annual rate of 5.1%. The purchase contracts entitle Cascade to quarterly contract adjustment payments of 1.525% per year on the stated amount of $25.00.
Each purchase contract obligates Cascade to purchase, and PNMR to sell, at a purchase price of $25.00 in cash, shares of PNMR's common stock on or before November 16, 2008 (the
49
"Purchase Contract Settlement Date"). Generally, the number of shares Cascade is obligated to purchase depends on the average closing price per share of PNMR's common stock over a 20-day trading period ending on the third trading day immediately preceding the Purchase Contract Settlement Date, subject to anti-dilution adjustments. If the average closing price for the 20-day trading period is equal to or greater than approximately $25.116 per share, the settlement rate will be 0.9954 shares of common stock. If the average closing price for the trading period is less than approximately $25.116 per share but greater than $20.93 per share, the settlement rate is equal to $25.00 divided by the average closing price of PNMR's common stock for the trading period. If the average closing price for the trading period is less than or equal to $20.93 per share, the settlement rate will be 1.1945 shares of common stock. Cascade has the option to settle its obligations under the purchase contracts at any time on or prior to the fifth business day immediately preceding the Purchase Contract Settlement Date. Prior to the Purchase Contract Settlement Date, the senior notes will be remarketed. If the remarketing is successful, the interest rate on the senior notes may change to a rate selected by the remarketing agent, and the maturity of the senior notes may be extended to a date selected by PNMR. If the remarketing of the senior notes is not successful, the maturity and interest rate of the senior notes will not change and holders of the equity units will have the option of putting their senior notes to PNMR to satisfy their obligations under the purchase contracts.
The purchase contracts are forward transactions in PNMR's common stock. The final accounting for this transaction is under review and will be finalized during the fourth quarter of 2005.
Before the issuance of common stock upon settlement of the purchase contracts, the equity units will be reflected in diluted earnings per share calculations using the treasury stock method as defined by SFAS 128. Under this method, the number of shares of common stock used in calculating diluted earnings per share (based on the settlement formula applied at the end of the reporting period) is deemed to be increased by the excess, if any, of the number of shares that would be issued upon settlement of the purchase contracts less the number of shares that could be purchased by PNMR in the market at the average market price during the period using the proceeds to be received upon settlement. Therefore, dilution will occur for periods when the average market price of PNMR's common stock for the reporting period is above approximately $25.116, and will potentially occur when the average price of PNMR's common stock for the 20-day trading period preceding the end of the reporting period is lower than the average price of PNMR's common stock for the full reporting period. As the transaction was entered into in October 2005, there was no dilution effect for the three and nine months ended September 30, 2005.
Common Stock and Equity Unit Offerings
In March 2005, PNMR issued 3,910,000 shares of its common stock at $26.76 per share. PNMR received net proceeds from this offering, after deducting underwriting discounts and commissions and estimated expenses, of approximately $101.0 million. In addition, in March
50
2005, PNMR completed a public offering of 4,945,000 equity units at 6.75% yielding net proceeds after fees of $239.6 million.
In conjunction with the acquisition of TNP, on June 6, 2005, PNMR made an equity investment of approximately $110.5 million in TNP, which TNP used to repay in full amounts owing under TNP's credit agreement. In addition, pursuant to PNMR's acquisition of TNP, PNMR agreed to provide funds to TNP to enable TNP to redeem (a) TNP's 14.5% Senior Redeemable Preferred Stock, Series C, (b) TNP's 14.5% Senior Redeemable Preferred Stock, Series D (collectively, "Preferred Stock"), and (c) TNP's 10.25% Senior Subordinated Notes due 2010, Series B ("Senior Notes"). On July 6, 2005, TNP redeemed the Preferred Stock by tendering $224.6 million to the holders of the Preferred Stock and redeemed the Senior Notes by tendering $296.5 million to holders of the Senior Notes. In order to fund a portion of the cost of redemption of TNP's Preferred Stock and Senior Notes, PNMR issued $370.0 million of commercial paper short-term notes under the PNMR commercial paper program. The balance of the funds necessary for the redemption came from other cash available to PNMR and the total redemption amount was an equity investment by PNMR in TNP.
Dividends
In July 2005, the Board of PNMR approved an 8.0% increase in PNMR's common stock dividend for an indicated annual rate of $0.80 per share. On July 19, 2005 and September 27, 2005, the Board of PNMR declared dividends on common stock of $0.20 per share to PNMR shareholders of record as of August 1, 2005 and November 1, 2005, respectively.
In August 2005, PNM entered into a new $400.0 million unsecured credit agreement (the "PNM Facility") to replace its existing $300.0 million facility. The PNM Facility is for a one-year term and expires August 17, 2006. Upon receiving approval by the NMPRC, it is expected that the term will be extended through August 17, 2010. The PNM Facility also includes two one-year extension options, subject to regulatory approval and approval by a majority of the lenders. In connection with entering into the new PNM Facility, PNM simultaneously terminated the previously existing $300.0 million facility, which would otherwise have terminated on November 21, 2006. Many of the same lenders were parties to the prior agreement. The terms and conditions of the new PNM Facility are generally similar to, or improvements over, the terms and conditions in the terminated agreement. At the time the previous credit facility was terminated, there was no balance on the facility and there were no fees or penalties related to the termination.
At September 30, 2005, PNM also had $23.5 million in local lines of credit and a $20.0 million borrowing arrangement with PNMR. There were no outstanding borrowings under the
51
PNM Facility, the local lines of credit or the borrowing arrangement with PNMR at September 30, 2005; however, $4.8 million of letters of credit were outstanding, which reduces the available capacity under the PNM Facility.
At September 30, 2005, PNM also had an AR Securitization program in place with a maximum borrowing capacity of $70.0 million. There were no amounts borrowed against the AR Securitization program at September 30, 2005.
PNM has a commercial paper program under which PNM may issue up to $300.0 million in commercial paper for up to 365 days. The commercial paper is unsecured and the proceeds are used for short-term cash management needs. The PNM Facility serves as a backstop for the outstanding commercial paper. As of September 30, 2005, PNM had $114 million in commercial paper outstanding.
PNM has a universal shelf registration statement filed with the SEC for the issuance of debt securities, equity securities, preferred stock, purchase contracts, purchase contract units and warrants. As of September 30, 2005, PNM had approximately $200.0 million of remaining unissued securities registered under its shelf registration statement.
In June 2005, the Board of PNM declared a dividend of $80.0 million that was paid to PNMR in July 2005.
In June 2005, TNMP filed an application with the NMPRC to become a borrower and issue notes of up to $100.0 million under the PNMR Facility. In July 2005, the NMPRC issued an order approving the application, SEC approval was received in September 2005 and TNMP was added as a borrower under the PNMR Facility in September 2005. Any borrowings made by TNMP under this sublimit are not guaranteed by PNMR. At September 30, 2005, TNMP had no outstanding borrowings under the PNMR Facility.
52
In June 2003, TNMP issued $250.0 million of 6.125% senior notes due in 2008. In May 2003, TNMP executed a $250.0 million Treasury rate lock transaction designed to manage interest rate risk associated with the issuance of the senior notes. TNMP paid $4.2 million upon the issuance of senior notes in June 2003 to settle the rate lock. Through the date of the acquisition, the cost of the rate lock was recorded in accumulated other comprehensive income and was being amortized to interest expense over the life of the senior notes. In conjunction with the acquisition of TNP by PNMR on June 6, 2005, the balance for the rate lock remaining in accumulated other comprehensive income was recorded at fair market value as of the date of acquisition in accordance with SFAS 141. The fair market value was determined to be zero and the balance of $1.7 million was charged to goodwill.
In September 2005, as part of the TNP acquisition financing, TNMP redeemed 1,090 shares of its privately held stock held by TNP at the book value of $56,888.91 per share, for a total of $62.0 million. TNP subsequently paid a cash dividend of $62.0 million to PNMR.
(7) Pension and Other Postretirement Benefit Plans
PNMR and its subsidiaries maintain a qualified defined benefit pension plan that was frozen in late 1997 with regard to new participants, a plan providing medical and dental benefits to eligible retirees, and an executive retirement program. PNMR maintains the legal obligation for the benefits owed to participants under these plans (the "PNM Plans"). TNMP also maintains a qualified defined benefit pension plan covering substantially all of its employees, a plan providing medical and death benefits to eligible retirees and an executive retirement program (the "TNMP Plans").
Participants in the PNM Plans currently include eligible employees and retirees of PNMR and other subsidiaries of PNMR. Participants in the TNMP Plans include eligible employees and retirees of TNMP, First Choice and other subsidiaries of TNP.
The total net periodic benefit cost or income from the PNM Plans, in addition to the net periodic benefit cost from the TNMP Plans from the date of PNMR's acquisition of TNP, or June 6, 2005 through September 30, 2005 is included in the consolidated statement of earnings of PNMR. The TNMP Plan amounts included in the results of PNMR are as follows: pension plan income of approximately $0.2 million, other postretirement benefit expense of approximately $0.2 million and executive retirement plan expense of less than $0.1 million.
53
PNM Plans
The following table shows the net periodic benefit cost or income of the PNM Plans.
Three Months Ended September 30,
Pension Plan
Other Post-Retirement Benefits
Executive Retirement Program
Components of Net Periodic
Benefit Cost/(Income)
Service cost
$ 477
$ 759
$ 718
$ 513
$ 16
$ 26
Interest cost
7,567
1,717
295
309
Expected return on assets
(10,042)
(9,709)
(1,329)
(1,232)
Transition obligation
454
Prior service cost amortization
79
(1,495)
(4,703)
Net loss amortization
892
888
1,549
1,271
Net Periodic Benefit Cost/(Income)
$ (1,027)
$ (431)
$ 1,160
$ (2,142)
$ 388
$ 406
Nine Months Ended September 30,
$ 1,431
$ 2,929
$ 2,008
$ 1,715
$ 48
$ 77
22,701
22,232
5,013
5,207
885
929
(30,126)
(29,395)
(3,965)
(3,696)
1,363
(4,899)
(6,803)
102
113
2,676
3,203
4,529
3,739
99
$ (3,081)
$ (794)
$ 2,686
$ 1,525
$ 1,164
$ 1,218
For the three months ended September 30, 2005 and 2004, PNM contributed approximately $1.5 million each period to trusts for other postretirement benefits. For the nine months ended September 30, 2005 and 2004, PNM contributed approximately $4.6 million each period to trusts for other postretirement benefits. PNM expects to make additional contributions during the remainder of 2005 totaling $1.5 million to trusts for other postretirement benefits. PNM does not anticipate making any contributions to the pension plan during 2005.
54
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 introduced a prescription drug benefit under Medicare, named Medicare Part D. In July 2005, the Company's Board approved a resolution amending its retiree health care plan in response to Medicare Part D, effective January 1, 2006, to reimburse retirees for their Medicare Part D premium up to $35.00 per month. The effect of this change was to increase expenses by $0.4 million for the third quarter of 2005. It is expected to increase expenses approximately $1.0 million for 2005. The fair market value of the postretirement benefit obligation was actuarially determined using a measurement date of August 1, 2005 and a discount rate of 5.50%, revised from 6.00% at December 31, 2004, based on the average yield of high quality investments. The weighted average expected rate of return on plan assets was 9.0%. There is no change to the on-going measurement date of the PNM other postretirement benefit plan; it will remain December 31.
55
TNMP Plans
The following table shows the net periodic benefit cost of the TNMP Plans.
$ 583
$ 469
$ 125
$ 104
$ 54
1,077
1,147
162
199
(1,791)
(1,573)
(104)
(88)
(25)
81
(29)
(21)
$ (131)
$ 14
$ 183
$ 296
$ 19
$ 97
Benefit Cost
$ 1,618
$ 1,407
$ 360
$ 308
$ 40
$ 161
3,297
3,442
496
509
103
(4,751)
(4,529)
(273)
136
243
(49)
(87)
(35)
(63)
118
Net Periodic Benefit Cost
$ 115
$ 233
$ 719
$ 824
$ 153
$ 365
For the three months ended September 30, 2005 and 2004, TNMP contributed approximately $0.3 million per period to trusts for the other postretirement benefits. For the nine months ended September 30, 2005 and 2004, TNMP contributed approximately $0.7 million each period to trusts for the other postretirement benefits. TNMP expects to make additional contributions during the remainder of 2005 totaling $0.3 million to trusts for other postretirement benefits. TNMP does not anticipate making any contributions to the pension plan during 2005.
56
In conjunction with the acquisition of TNP by PNMR on June 6, 2005, the benefit obligations for the TNMP Plans were recorded at the fair market value as of the date of acquisition in accordance with SFAS 141 and as a result, PNMR recorded an additional pension and postretirement liability of $5.5 million which increased goodwill. The fair market value of the obligations was actuarially determined using a measurement date of June 6, 2005 and a discount rate of 5.25%, revised from 5.75% at December 31, 2004, based on the average yield of high quality investments. The weighted average expected rate of return on plan assets was 9.0% for the pension and executive retirement plans and 6.9% for the other postretirement plans. There is no change to the on-going measurement date of the TNMP Plans; it will remain December 31.
(8) Commitments and Contingencies
There are various claims and lawsuits pending against the Company. The Company is also subject to federal, state and local environmental laws and regulations, and is currently participating in the investigation and remediation of numerous sites. In addition, the Company periodically enters into financial commitments in connection with its business operations. It is not possible at this time for the Company to determine fully the effect of all litigation and other legal proceedings on its consolidated financial statements. However, the Company has recorded a liability where the litigation effects can be reasonably estimated and where an outcome is considered probable. The Company does not expect that any known lawsuits, environmental costs and commitments will have a material adverse effect on its financial condition or results of operations, although the outcome of litigation, investigations and other legal proceedings is inherently uncertain.
The Company is involved in various legal proceedings in the normal course of its business. The associated legal costs for these legal matters are accrued when incurred. It is also the Company's policy to accrue for legal costs expected to be incurred in connection with SFAS No. 5, "Accounting for Contingencies" ("SFAS 5"), legal matters when it is probable that a SFAS 5 liability has been incurred and the amount of expected legal costs to be incurred is reasonably estimable. These estimates include costs for external counsel and other professional fees.
Tax Refund Litigation
In November 2004, the United States Department of Justice filed a complaint against the Company in federal court, alleging that approximately $4.2 million of income tax refunds claimed and received for the 1998 and 1999 tax years were erroneously paid. The complaint sought return of that refund amount, plus interest, a 10% surcharge and costs. The Company filed an answer in response to the complaint denying all the material allegations.
57
The suit arose from refunds granted in connection with the 1998 and 1999 tax years. The refunds were claimed on amended returns filed in September 2002 and were paid by the IRS in November and December 2002. The government's complaint alleged that the Company did not correctly elect to deduct research and experimental expenses, and that certain costs did not qualify as research and experimental. Therefore, the government asserted that the Company is not entitled to the refunds. In July 2005, the Company settled with the DOJ. A joint stipulation of dismissal with prejudice was filed with the court in July 2005.
PVNGS Liability and Insurance Matters
The PVNGS participants have financial protection for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300.0 million and the balance by an industry‑wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the primary liability insurance limit, PNM could be assessed retrospective adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $101.0 million. The retrospective assessment was subject to an annual limit of $10.0 million per reactor per incident that was increased to $15.0 million as described below under "Price-Anderson Act Renewal." Based upon PNM's 10.2% interest in the three PVNGS units, PNM's maximum potential assessment per incident for all three units is approximately $31.0 million, with an annual payment limitation of approximately $4.5 million based on the annual limit per reactor per incident of $15.0 million as discussed above. If the funds provided by this retrospective assessment program prove to be insufficient, Congress could impose revenue-raising measures on the nuclear industry to pay claims.
Price-Anderson Act Renewal
The Energy Policy Act of 2005 (see "Energy Policy Act" below in Note 9) extends the Price-Anderson Act for 20 years. The Price-Anderson Act provides for immediate, no-fault insurance coverage for the public in case of a nuclear reactor accident. It requires nuclear plant operators to purchase all the private insurance available to them (currently $300.0 million) to serve as a primary level of coverage. If this amount is insufficient to cover claims arising from an accident, companies are required to contribute to a fund that provides a secondary level of coverage. The Energy Policy Act of 2005 raises the maximum required fee at the secondary level from $63.0 million to $95.8 million per reactor, which is already reflected in the $101.0 million maximum assessment discussed under "PVNGS Liability and Insurance Matters" above, which includes a provision for legal costs, and raises the annual secondary level payout from $10.0 million to $15.0 million per reactor, adjusting the payout for inflation in the future.
58
Water Supply
Because of New Mexico's arid climate and current drought conditions, there is a growing concern in New Mexico about the use of water for power plants. The availability of sufficient water supplies to meet all the needs of the state, including growth, is a major issue. The Company has secured water rights in connection with the Afton, Luna and Lordsburg plants and water availability does not appear to be an issue for these plants at this time.
The Four Corners region of New Mexico, in which SJGS and Four Corners are located, experienced drought conditions during 2002 through 2004 that could have affected the water supply for the Company's generation plants. In future years, if adequate precipitation is not received in the watershed that supplies the Four Corners region, the plants could be impacted. Consequently, PNM, APS and BHP Billiton have undertaken activities to secure additional water supplies for SJGS, Four Corners and related mines. The USBR was requested to approve two supplemental contracts, one with the Jicarilla Apache Nation, PNM, and BHP Billiton for the SJGS and a second contract with the Jicarilla Apache Nation, APS and BHP Billiton for Four Corners, for a one-year term ending December 31, 2005. Approvals for the agreement have been obtained. PNM has also entered into a voluntary shortage sharing agreement with tribes and other water users in the San Juan Basin for a one-year term ending December 31, 2005. Approvals for the agreement have been obtained. Similar agreements were entered into in 2003 and 2004. PNM is also in discussion for a supplemental contract and shortage sharing agreement for 2006. Although the Company does not believe that its operations will be materially affected by the drought conditions at this time, it cannot forecast the weather situation or its ramifications, or how regulations and legislation may impact the Company's situation in the future, should the shortages occur in the future.
Conflicts at San Juan Mine Involving Oil and Gas Leaseholders
The SJCC, through leases with the federal government and the State of New Mexico, owns coal interests with respect to the San Juan underground mine. Certain gas producers have leases in the area of the underground coal mine and have asserted claims against SJCC that its coal mining activities are interfering with gas production. Western Gas has filed an appeal to the IBLA to contest a recent decision by BLM to allow SJCC to mine within a less restrictive distance of the existing gas wells. The Company understands that SJCC has reached a settlement in principle with Western Gas for certain wells in the mine area and that the IBLA proceeding will be dismissed. The Western settlement however, does not resolve all of Western's potential claims in the larger San Juan underground mine area. SJCC has also reached a settlement with another gas leaseholder, Burlington Resources for certain wells in the mine area. The Company cannot predict the outcome of any future disputes between SJCC and Western Gas or other gas leaseholders.
Navajo Nation Environmental Issues
Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government as well as a lease from the Navajo Nation. APS is the Four Corners operating agent and PNM owns a 13% ownership interest in Units 4 and 5 of Four Corners.
In July 1995, the Navajo Nation enacted the Navajo Acts. The Navajo Acts purport to give the Navajo Nation EPA authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners. On October 17, 1995, the Four Corners participants filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, challenging the applicability of the Navajo Acts as to Four Corners. The District Court has stayed these proceedings pursuant to a request by the parties. In May 2005, APS and the Navajo Nation signed a Voluntary Compliance Agreement which would resolve the dispute regarding the air pollution and control acts portion of the lawsuit for the term of the Voluntary Compliance Agreement. Provided that the EPA acts consistent with the Voluntary Compliance Agreement, including delegating Clean Air Act authority to the Navajo Nation, APS will dismiss the pending claims related to the Clean Air Act.
In February 1998, the EPA issued regulations identifying those Clean Air Act provisions for which it is appropriate to treat Native American tribes in the same manner as states. The EPA has announced that it has not yet determined whether the Clean Air Act would supersede pre-existing binding agreements between the Navajo Nation and the Four Corners participants that could limit the Navajo Nation's environmental regulatory authority over Four Corners. The Company believes that the Clean Air Act does not supersede these pre-existing agreements. The Company cannot currently predict the outcome of this matter.
In April 2000, the Navajo Tribal Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. The Four Corners participants believe that the regulations fail to recognize that the Navajo Nation did not intend to assert jurisdiction over Four Corners. In July 2000, each of the Four Corners participants filed a petition with the Navajo Supreme Court for review of the operating permit regulations. Those proceedings have been stayed, pending the settlement negotiations mentioned above. The Company cannot currently predict the outcome of this matter.
New Source Review Rules
In November 1999, the DOJ, at the request of the EPA, filed complaints against seven companies, alleging that the companies over the past 25 years had made modifications to their plants in violation of the NSR requirements and in some cases the NSPS regulations, which could result in the requirement to make costly environmental additions to older power plants. Whether or not the EPA will ultimately prevail is uncertain at this time. There have been a number of decisions regarding the pending enforcement cases against the seven companies, and some cases have been settled. Some of the decisions have ruled in favor of the EPA and others have ruled in favor of the companies. The two most recent decisions, the Alabama Power
60
Company decision and the Fourth Circuit Court of Appeals decision in the Duke Energy case, accepted the legal theories advanced by the companies. In October 2005, the EPA proposed changes to its NSR permitting program for electric generating units. This proposal would establish a new emissions test for NSR based on the current NSPS hourly emission increase test. The EPA indicated in the proposal that the Fourth Circuit Court of Appeals decision in the Duke Energy case is one of the reasons for proposing these changes. At the same time the EPA announced the proposed changes, it also issued a memorandum to the EPA regions reporting that the agency's strategy to reduce emissions from coal-fired power sector is working primarily through the Clean Air Interstate Rule and the regional haze rule, and that it is time to refocus the EPA's enforcement efforts on other areas.
No complaint has been filed against PNM by the EPA, and the Company believes that all of the RMRR work undertaken at its power plants was and continues to be in accordance with the requirements of NSR and NSPS. However, in October 2000, the NMED made an information request of PNM, advising PNM that the NMED was in the process of assisting the EPA in the EPA's nationwide effort of verifying that changes made at the country's utilities have not inadvertently triggered a modification under the Clean Air Act's PSD policies. PNM has responded to the NMED information request. In June 2002, PNM received another information request from the NMED for a list of capital projects budgeted or completed in 2001 or 2002. PNM has responded to the additional NMED information request.
In December 2002, the EPA promulgated certain long-awaited revisions to the NSR rules, along with proposals to revise the RMRR exclusion contained in the regulations. In August 2003, the EPA issued its rule regarding RMRR, clarifying what constitutes RMRR of damaged or worn equipment, subject to safeguards to assure consistency with the Clean Air Act. It provides that replacements of equipment are routine only if the new equipment is (i) identical or functionally equivalent to the equipment being replaced; (ii) does not cost more than 20% of the replacement value of the unit of which the equipment is a part; (iii) does not change the basic design parameters of the unit; and (iv) does not cause the unit to exceed any of its permitted emissions limits. Legal challenges to the RMRR rule have been filed by several states; other states have intervened in support of the rule. How such challenges will ultimately be resolved cannot be predicted but an appellate court order has stayed the effect of the RMRR rule pending the outcome of the litigation. Also in late 2003 and early 2004, several groups filed petitions requesting the EPA to reconsider several aspects of the RMRR rule. In June 2005, the EPA published its decision in response to the petitions for reconsideration. EPA rejected all of the petitioner's requests and reaffirmed the RMRR rule. The Company is unable to determine the impact of this matter.
The Clean Air Act
In July 1999, the EPA published its final regional haze regulations and in May 2004, the EPA proposed revisions to the regulations and proposed guidelines for best available retrofit technology. The purpose of the regional haze regulations is to address regional haze visibility
61
impairment in the 156 Class 1 areas in the nation, which consist of national parks, wilderness areas and other similar areas. The final rule calls for all states to establish goals and emission reduction strategies for improving visibility in all the Class 1 areas. These rules were litigated, and in 2002 portions of the rule were vacated and remanded. In early 2005, the United States Court of Appeals for the District of Columbia Circuit found that the EPA's Western Regional Air Partnership Annex regulation, an optional alternative approach for western states, was illegal. In June 2005, the EPA issued the Clean Air Visibility Rule. This rule addressed the issues that were vacated and remanded in 2002. The EPA issued a proposed rule in the summer of 2005 to address the Western Regional Air Partnership Annex rule that had been successfully challenged in the United States Court of Appeals for the District of Columbia Circuit. The proposed rule addresses alternative strategies to accomplish the requirements of the regional haze rule.
The Company cannot predict at this time what the impact of the implementation of the regional haze rule will be on the Company's coal-fired power plant operations. Potentially, additional sulfur dioxide emission reductions and nitrogen oxide emission reductions could be required. The nature and cost of compliance with these potential requirements cannot be determined at this time. However, the Company does not anticipate any material adverse impact on its financial condition or results of operations.
Citizen Suit Under the Clean Air Act
The GCT filed a citizen suit in federal district court in New Mexico against PNM (but not against the other SJGS co-owners) in May 2002. The suit alleged two violations of the Clean Air Act and related regulations and permits. First, GCT argued that the plant had violated the federal PSD rules, as well as the corresponding provisions of the New Mexico Administrative Code, at SJGS Units 3 and 4. Second, GCT alleged that the plant had "regularly violated" the 20% opacity limit contained in SJGS's operating permit and set forth in federal and state regulations at Units 1, 3 and 4. The lawsuit sought penalties as well as injunctive and declaratory relief. PNM denied the material allegations in the complaint.
By letter dated April 29, 2004, GCT provided a notice of intent to sue as a jurisdictional prerequisite to filing another citizens' suit under the Clean Air Act. The notice of intent contained allegations that PNM continued to violate the applicable opacity standard for SJGS Units 1, 3 and 4 following the filing of the suit above, that PNM violated its duty to operate SJGS in a manner consistent with good air pollution control practices for minimizing pollution and that PNM failed to properly report emissions deviations and certify compliance with applicable air emissions standards.
By order of the court, PNM and GCT entered into settlement discussions. The discussions were expanded to include the NMED to address the "Excess Emission Reports" disclosed below. In March 2005, PNM entered into a consent decree with the NMED and GCT which was approved by the court in May 2005. Under the terms of the consent decree, PNM
62
and other plant owners will invest more than $200.0 million in new pollution control technology. The capital costs of the technology are currently estimated to be at least $140.0 million, with an additional $70.0 to $80.0 million estimated for operating and maintenance costs over the next 10years. PNM is continuing to work with its consultants and project engineers to refine the costs so that the consent decree is complied with in the most economical, efficient and effective manner. PNM's portion of costs will be approximately 47% of the total capital and operating costs. In addition, the consent decree provides that stipulated penalties are payable to the NMED if SJGS emissions exceed specified quarterly averages over the course of a calendar year. PNM cannot predict the specific amount of potential liability for any stipulated penalties until the end of 2005. The consent decree resolves the foregoing lawsuit, the notice of intent, and certain threatened air quality claims by the NMED (see "Excess Emissions Reports" below). PNM plans to file for an air permit with the NMED prior to starting construction on certain new equipment required by the consent decree. The issue of the plaintiffs' attorney fees and costs has been resolved.
Four Corners Air Emissions
The GCT, Sierra Club and National Parks Conservation Association, petitioned the EPA to issue a FIP and a final Title V operating permit to regulate air emissions from Four Corners. The FIP has been pending at the EPA since 1999, and the petition seeks to speed up the process of issuance. The Company is unable to predict the outcome of this proceeding, but does not anticipate any material adverse impact on PNMR's or PNM's financial condition or results of operations. APS is the operator of Four Corners, and PNM will continue to monitor developments in this proceeding.
Excess Emissions Reports
As required by law, whenever there are excess emissions from SJGS, due to such causes as start-up, shutdown, upset, breakdown or certain other conditions, PNM makes filings with the NMED. For several years, PNM had been in discussions with NMED concerning excess emissions reports for the period after January 1997. In May 2004, the NMED issued a "draft" compliance order that included allegations that SJGS violated certain applicable air quality limitations. This matter was resolved in conjunction with the GCT settlement described above under "Citizen Suit Under the Clean Air Act."
Archaeological Site Disturbance
PNM hired Great Southwestern to conduct certain climb and tighten activities on a number of electric transmission lines in New Mexico during 2001. Those lines traverse a combination of federal, state, tribal and private properties in New Mexico. In late May 2002, the USFS notified PNM that apparent disturbances to archeological sites had been discovered in and around the rights-of-way for PNM's transmission lines in the Carson National Forest in
63
New Mexico. Great Southwestern had performed climb and tighten activities on those transmission lines.
PNM confirmed the existence of the disturbances, as well as disturbances associated with certain arroyos that may raise issues under the Clean Water Act. PNM contracted for an archeological assessment and a proposed remediation plan with respect to the disturbances and has provided the assessment to the USFS and the federal Bureau of Land Management. The Santa Fe National Forest issued a notice of non-compliance to PNM for alleged non-compliance with the terms and conditions of PNM's special use authorization relating to maintenance of PNM's power lines on USFS land.
In June 2004, PNM and Great Southwestern entered into a letter agreement with the NNHPD for a survey of potential impacts on Navajo Nation land to determine if disturbed cultural resources exist. Under the terms of the June 2004 letter agreement, the NNHPD agreed to release all claims against PNM and Great Southwestern for any impacts on Navajo Nation land arising from the climb and tighten project. PNM provided survey reports to the NNHPD that were accepted by the Navajo Nation in October 2005 and the Company was notified that the NNHPD has determined that damage resulting from the climb and tighten project was minimal and a treatment plan will not be necessary. The NNHPD and the Navajo Nation Division of Natural Resources are of the opinion that PNM has complied fully with the stipulations set forth in the June 2004 letter, and as such, NNHPD requires no further work from PNM or Great Southwestern.
Santa Fe Generating Station
PNM and the NMED conducted investigations of gasoline and chlorinated solvent groundwater contamination detected beneath PNM's former Santa Fe Generating Station site to determine the source of the contamination pursuant to a 1992 Settlement Agreement between PNM and the NMED.
PNM believes that the data compiled indicates observed groundwater contamination originated from off-site sources. However, in August 2003, PNM elected to enter into a fifth amendment to the 1992 Settlement Agreement with the NMED to avoid a prolonged legal dispute, whereby PNM agreed to supplement remediation facilities by installing an additional extraction well and two new monitoring wells to address remaining gasoline contamination in the groundwater at and in the vicinity of the site. PNM will continue to operate the remediation facilities until the groundwater is cleaned up to applicable federal standards or until such time as the NMED determines that additional remediation is not required, whichever is earlier. The City of Santa Fe, the NMED and PNM entered into an amended Memorandum of Understanding relating to the continued operation of the well and the remediation facilities called for under the latest amended Settlement Agreement.
64
In September 2003, PNM was verbally informed that the Superfund Oversight Section of the NMED is conducting an investigation into the chlorinated solvent contamination in the vicinity of the former Santa Fe Generating Station site. The investigation will study possible sources for the chlorinated solvents in the groundwater. The NMED investigation is ongoing.
Natural Gas Royalties Qui Tam Litigation
In 1999, a complaint was served alleging violations of the False Claims Act by PNM and its subsidiaries, Gathering Company and Processing Company (collectively, the "Company" for purposes of this discussion), by purportedly failing to properly measure natural gas from Federal and tribal properties in New Mexico, and consequently, underpaying royalties owed to the Federal government. A private relator is pursuing the lawsuit. The complaint was served after the DOJ declined to intervene to pursue the lawsuit. The complaint seeks actual damages, treble damages, costs and attorneys fees, among other relief.
The Company is currently participating with other defendants in a motion to dismiss on the ground that the relator does not meet certain jurisdictional requirements for bringing suit under the False Claims Act. In May 2005, a Special Master issued a report that recommended to the court that several defendants, including the Company, be dismissed from the case on this ground. The relator has objected to the Special Master's recommendation regarding the Company. The Chief Judge of the federal district court for the District of Wyoming will hear and rule on the objection. The Company is vigorously defending this lawsuit. If the Special Master's recommendation regarding dismissal of the Company on jurisdictional grounds is not sustained, the Company is unable to estimate the potential liability, if any, or to predict the ultimate outcome of this lawsuit.
Asbestos Cases
PNM was named in 2003 as one of a number of defendants in 21 personal injury lawsuits relating to alleged exposure to asbestos. All of these cases involve claims of individuals, or their descendents, who worked for contractors building, or working at, PNM power plants. Some of the claims relate to construction activities during the 1950s and 1960s, while other claims generally allege exposure during the last 30 years. PNM has never manufactured, sold or distributed products containing asbestos. PNM has been dismissed with prejudice from all but two of the remaining cases. PNM was insured by a number of different insurance policies during the time period at issue in these cases. Although the Company is unable to fully predict the outcome of this litigation, the Company believes that these legal proceedings will not have a material impact on its financial condition.
SESCO Matter
In October 2003, the TCEQ requested information from PNM concerning any involvement that PNM had with SESCO, a former electrical equipment repair and sales company located in San Angelo, Texas. PNM was informed that the TCEQ and the EPA claim to have identified contamination of the soil and groundwater at the site.
65
TCEQ is conducting a site investigation of a SESCO facility pursuant to the Texas Solid Waste Act and the SESCO site has been referred to the Superfund Site Discovery and Assessment Program. The primary concern appears to be polychlorinated biphenyls in soil and groundwater on and adjacent to the site. The TCEQ is conducting the site investigation to determine what remediation activities are required at the SESCO site and to identify potentially responsible parties. In January 2004, PNM submitted its preliminary response to the TCEQ request for information. The response states that PNM previously had a requirements contract with SESCO for the repair of electric transformers. It appears that a number of transformers were sent to SESCO for repair. In addition, it appears that PNM sold a number of retired transformers to SESCO. An informational meeting took place in Austin, Texas in April 2004 where the status of the SESCO site and the possible establishment of a potentially responsible parties' committee was discussed. In February 2005, PNM agreed to participate in the potentially responsible parties' committee known as the "Working Group". PNM is voluntarily participating with the others in the investigation and may participate in any required remediation at the SESCO facility. Common counsel was recently hired to represent the common interests of the members of the Working Group. The Working Group's investigation into persons and entities that sent transformers and other equipment to SESCO is ongoing. In addition, the Working Group sent a request for proposal for an environmental contractor to perform a remedial investigation and assessment study for the SESCO site and is currently reviewing responses. PNM is still investigating its role in the matter, and is unable to predict the outcome at this time. As discussed below, TNMP is also involved in the SESCO matter.
Coal Combustion Waste Disposal
SJCC currently disposes of coal combustion products consisting of fly ash, bottom ash, and gypsum from SJGS in the surface mine pits adjacent to the plant. PNM and SJCC have been participating in various sessions sponsored by EPA to consider rulemaking for the disposal of coal combustion products. The rulemaking would be pursuant to the Bevill Amendment of the Resource Conservation and Recovery Act. PNM cannot predict the outcome of this matter but does not believe currently that it will have a material adverse impact on the financial condition of the Company or its operations.
Western United States Wholesale Power Market
Various circumstances, including electric power supply shortages, weather conditions, gas supply costs, transmission constraints, and alleged market manipulation by certain sellers, resulted in the well-publicized "California energy crisis" and in the bankruptcy filings of the Cal PX and of PG&E. However, since the third quarter of 2001, conditions in the Western wholesale power market have changed substantially because of regulatory actions, conservation measures, the construction of additional generation, a decline in daily natural gas prices relative to levels reached during the California energy crisis and regional economic conditions.
66
As a result of the foregoing conditions in the Western market, the FERC and other federal and state governmental authorities initiated investigations, litigation and other proceedings relevant to the Company and other sellers. The more significant of these in relation to the Company are summarized below.
California Refund Proceeding
SDG&E and other California buyers filed a complaint with the FERC in 2000 against sellers into the California wholesale electric market. Hearings were held in September 2002, and the ALJ issued the "Proposed Findings on California Refund Liability" in December 2002, in which it was determined that the Cal ISO had, for the most part, correctly calculated the amounts of the potential refunds owed by sellers. The ALJ identified what were termed "ballpark" figures for the amount of refunds due under the order in an appendix to the proposed findings document. Pursuant to the FERC's order, PNM filed, in conjunction with the competitive supplier group, initial comments in January 2003 to the ALJ's preliminary findings addressing errors the Company believes the ALJ made in the proposed findings, and filed reply comments in February 2003.
Prior to the December 2002 ALJ decision, the Ninth Circuit ordered the FERC to allow the parties in the case to provide additional evidence regarding alleged market manipulation by sellers. Several California parties submitted additional evidence in March 2003 to support their position that virtually all market participants, including PNM, either engaged in specific market manipulation strategies or facilitated such strategies. PNM maintains that it did not engage in improper wholesale activities, and filed reply evidence in March 2003, denying the allegations against it.
In March 2003, the FERC issued an order substantially adopting the ALJ's findings in the December 2002 decision, but requiring a change to the formula used to calculate refunds. The FERC raised concerns that the indices for California gas prices, a major element in the refund formula, had been subject to potential manipulation and were unverifiable. The effect of this change would be to increase PNM's refund liability. In October 2003, the FERC issued its order on rehearing in which it affirmed its decision to change the gas price indices used to calculate the refund amounts. This has the effect of increasing the Company's amount of refund. The precise amounts, however, will not be certain until the Cal ISO and Cal PX recalculate the refund amounts. In a report filed by the Cal ISO in March 2005, the Cal ISO indicated that the Cal PX had concluded its recalculation of the adjustments for hourly price mitigation. The Cal ISO is waiting to receive audited fuel cost information from market participants as a result of the fuel cost proceedings currently pending at the FERC before finalizing its recalculated refund amounts. In August 2005, the FERC issued an order setting out the process by which sellers into the Cal ISO and Cal PX markets could make their cost recovery filings pursuant to the FERC's prior orders that indicated sellers would get the opportunity to submit evidence demonstrating that the refund methodology creates a revenue shortfall for their transactions
67
during the refund period. Included in PNM's submittal were objections to the limited amount of time the FERC allowed for sellers to complete their respective submittals, and the FERC's arbitrary decision to allow only marketers and not load serving entities such as PNM to include a return component in their cost filings. PNM participated with other competitive sellers to request rehearing of these issues before the FERC. In September 2005, PNM made its cost recovery filing identifying its costs associated with sales into the California Cal ISO and Cal PX markets during the refund period. PNM's cost recovery filing is still pending before FERC. In addition, the Company has engaged in discussions with California parties based upon a template provided by FERC, but is unable to predict whether settlement will be reached.
In September 2004, the Ninth Circuit issued its decision in one of the lead appellate cases addressing the FERC's refund order. The Ninth Circuit upheld the FERC's authority to establish the market-based rate framework under the Federal Power Act, but held that the FERC violated its administrative discretion by declining to investigate whether it should order refunds from sellers who failed to provide transaction-specific reports to the FERC as required by its rules. The Ninth Circuit determined that the FERC has the authority to order refunds for these transactions if it elects to do so and remanded the case to the FERC for further proceedings, including a determination as to whether additional refunds are appropriate. PNM participated with other competitive sellers requesting rehearing by the Ninth Circuit, which is still pending. Additional appeals are still pending before the Ninth Circuit, includingCPUC vs FERC, a case addressing the scope of market transactions subject to refund. PNM has participated in this appeal as one of the members of the competitive sellers group. The Company cannot predict the ultimate outcome of any FERC proceeding that may result from these appeals, or whether PNM will be ultimately directed to make any additional future refunds as the result of the decision; however, the Company has recorded a reserve for this contingency.
Pacific Northwest Refund Proceeding
In addition to the California refund proceedings, Puget Sound Energy, Inc. filed a complaint at the FERC alleging that spot market prices in the Pacific Northwest wholesale electric market were unjust and unreasonable. In September 2001, the ALJ issued a recommended decision and declined to order refunds associated with wholesale electric sales in the Pacific Northwest. In a ruling similar to the one issued in the California refund proceeding, the FERC allowed additional discovery to take place and the submission of additional evidence in the case in March 2003. In June 2003, the FERC issued an order terminating the proceeding and adopting the ALJ's recommendation that no refunds should be ordered. Several parties in the proceeding filed requests for rehearing and in November 2003, the FERC denied rehearing and reaffirmed its prior ruling that refunds were not appropriate for spot market sales in the Pacific Northwest during the first half of 2001. In November 2003, the Port of Seattle filed an appeal of the FERC's order denying rehearing in the Ninth Circuit, which is still pending. As a participant in the proceedings before the FERC, PNM is also participating in the appeal proceedings. The Ninth Circuit had originally scheduled oral arguments in the appeal for
68
September 2005, but subsequently continued the oral argument after moving the case to a different panel of judges than those originally assigned. The Company is unable to predict the ultimate outcome of this appeal, or whether PNM will ultimately be directed to make any refunds.
FERC Show Cause Orders
The FERC initiated a market manipulation investigation, partially in response to the bankruptcy filing of the Enron Corporation and to allegations that Enron Corporation may have engaged in manipulation of portions of the Western wholesale power market. In connection with that investigation, all sellers into Western electric and gas markets were required to submit data regarding short-term transactions in 2000-2001. In March 2003, the FERC staff issued its final report, which addressed various types of conduct that the FERC staff believed may have violated market monitoring protocols in the Cal ISO and Cal PX tariffs. Based on the final report, the FERC issued orders to certain companies, including Enron Corporation, requiring them to show cause why the FERC should not revoke their authorizations to sell electricity at market-based rates. In addition, the FERC staff recommended that the FERC issue orders requiring certain entities to show cause why they should not be required to disgorge profits associated with conduct deemed to violate the Cal ISO and Cal PX tariffs, or be subject to other remedial action.
In June 2003, the FERC issued two separate orders to show cause against PNM and over sixty other companies. In the first order, the Gaming Practices Order, the FERC asserted that certain entities, including PNM, appeared to have participated in activities that constitute gaming and/or anomalous market behavior in violation of the Cal ISO and Cal PX tariffs during the period January 1, 2000 to June 20, 2001. Specifically, PNM is alleged to have engaged in a practice termed "False Import," which the FERC defined as the practice of exporting power generated by California and then reimporting it into California in order to avoid price caps on energy generated in California. These allegations are based primarily on an initial Cal ISO report and the additional evidentiary submission by California parties. The Cal ISO was ordered to submit additional information on which the entities subject to the Show Cause Order should respond. For PNM, the potential disgorgement for alleged "False Import" transactions covers the period May 1, 2000 to October 1, 2000. After review of the additional Cal ISO data and consultation with PNM, the FERC trial staff filed a motion to dismiss PNM from the case in August 2003. In September 2003, the California parties filed their objection to the dismissal of PNM from the case. In January 2004, the FERC issued an order granting trial staff's motion to dismiss PNM from the Gaming Practices docket on grounds that the FERC staff's investigation did not reveal that PNM engaged in the practice of "False Import." As a result, the Company has been dismissed from the Gaming Practices proceedings.
In the second order to show cause, the Gaming Partnerships Order, the FERC asserted that certain entities, including PNM, acted in concert with Enron Corporation and other market participants to engage in activities that constitute gaming and/or anomalous market behavior
69
in violation of the Cal ISO and Cal PX tariffs during the period January 1, 2000 to June 20, 2001. Specifically, PNM is alleged to have entered into "partnerships, alliances or other arrangements" with thirteen of its customers that allegedly may have been used as market manipulation schemes. The precise basis for certain of the FERC's allegations is not clear from the Gaming Partnerships Order, although it appears that most arise out of PNM's provision of "parking and lending" services to the identified companies. The potential remedies include disgorgement of unjust profits, as well as non-monetary remedies such as revocation of a seller's market-based rate authority.
In September 2003, PNM filed its responses to the Gaming Partnerships Order indicating that it did not engage in the alleged "partnerships, alliances or other arrangements" with the alleged parties. In October 2003, PNM filed testimony and exhibits in the case reasserting its response previously filed. In January 2004, the FERC issued an order granting the FERC staff's motion to dismiss seven of the thirteen PNM customers on grounds that there was no evidence to conclude that these companies used their commercial relationship with PNM to game the Cal ISO and Cal PX markets. In February 2004, the FERC staff and the California parties filed testimony in the case. The FERC staff did not identify any improper conduct by PNM. The California parties alleged that PNM provided false information regarding parking transactions that allowed other parties to game the California market. In March 2004, the FERC approved the settlements entered into by two of the thirteen PNM customers and dismissed another of PNM's customers from the proceeding. Of the three remaining PNM customers in the docket, the FERC staff entered into settlement agreements with two of them. In May 2004, the Chief ALJ issued an order suspending the procedural schedule in the docket pursuant to the California parties' request to enable the parties to engage in settlement discussions of all matters related to the "California energy crisis." In September 2004, the FERC staff filed a motion to dismiss PNM from the docket and to enter into a settlement of certain parking and lending transactions. The staff's motion stated that after investigation and review there was no evidence that PNM either engaged in a gaming practice that violated the Cal ISO or Cal PX tariffs by directly transacting through the Cal ISO or Cal PX markets, or shared any unjust profits earned by PNM's customers that may have engaged in gaming practices. Additionally, PNM entered into a settlement of certain matters outside the scope of the docket related to historic parking and lending transactions, under which PNM agreed not to provide parking and lending services prospectively without first meeting certain requirements agreed to with the FERC staff. Additionally, PNM agreed to pay $1.0 million in settlement to the FERC to obtain satisfaction of all issues related to any potential liability stemming from the provision of such services historically. In October 2004, the California parties filed their opposition to the motion to dismiss and settlement. Both PNM and the FERC staff made filings in which they vigorously supported the motion to dismiss PNM from the docket and the settlement reached with the FERC staff. In July 2005, the FERC issued its order granting the staff's motion to dismiss PNM from the Gaming Partnerships docket. In its order, the FERC agreed with its trial staff's assessment of the record in the case and found that PNM did not engage in prohibited gaming practices as defined in the FERC's Gaming Partnership Order during the relevant time period. The FERC also approved the settlement on the parking and lending services, finding that the
70
settlement covered matters that were beyond the scope of matters set for hearing as part of the Gaming Partnerships Order. The FERC also denied the California parties' request to keep the docket open as to PNM and terminated the PNM docket. In August 2005, as anticipated, the California parties filed their petition for rehearing at the FERC objecting to the FERC's dismissal of PNM from the Gaming Partnership investigation and objecting to the settlement reached with the FERC staff. The petition for rehearing is pending before FERC and PNM cannot predict the ultimate outcome of the rehearing petition.
California Power Exchange and Pacific Gas and Electric Bankruptcies
In January and February 2001, SCE and the major purchasers of power from the Cal ISO and Cal PX, defaulted on payments due to the Cal ISO for power purchased from the Cal PX in 2000. These defaults caused the Cal PX to seek bankruptcy protection. PG&E subsequently also sought bankruptcy protection. PNM has filed its proofs of claims in the Cal PX and PG&E bankruptcy proceedings. Amounts due to PNM from the Cal ISO or Cal PX for power sold to them in 2000 and 2001 total approximately $7.9 million. Both the PG&E and Cal PX bankruptcy cases have confirmed plans of reorganization in which the claims of various creditors have been specially classified and are waiting a final determination by the FERC before the claims are actually paid. The PG&E bankruptcy case has an escrow account and the Cal PX bankruptcy has established a settlement account, both of which are awaiting a determination by the FERC setting the level of claims and allocating the funds.
California Attorney General Complaint
In March 2002, the California Attorney General filed a complaint with the FERC against numerous sellers regarding prices for wholesale electric sales into the Cal ISO and Cal PX markets and to the California Department of Water Resources. PNM was among the sellers identified in this complaint and filed its answer and motion to intervene. In its answer, PNM defended its pricing and challenged the theory of liability underlying the California Attorney General's complaint. In May 2002, the FERC entered an order denying the California Attorney General's request to initiate a refund proceeding, but directed sellers, including PNM, to comply with additional reporting requirements with regard to certain wholesale power transactions. PNM has made filings required by the May 2002 order. The California Attorney General filed a petition for review in the Ninth Circuit. PNM intervened in the Ninth Circuit appeal and participated as a party in that proceeding. As noted above, in September 2004, the Ninth Circuit issued its decision upholding the FERC's authority to establish the market-based rate framework under the Federal Power Act, but held that the FERC violated its administrative discretion by declining to investigate whether it should order refunds from sellers who failed to provide transaction-specific reports to the FERC as required by its rules. The Ninth Circuit determined that the FERC has the authority to order refunds for these transactions if it elects to do so and remanded the case back to the FERC for further proceedings, including a determination as to whether additional refunds are appropriate. PNM participated with other competitive sellers requesting rehearing en banc by the Ninth Circuit, which is still pending.
71
The Company cannot predict the ultimate outcome of the FERC proceeding on remand, or whether PNM will be ultimately directed to make any additional refunds as the result of the decision.
California Antitrust Litigation
Several class action lawsuits have been filed in California state courts against electric generators and marketers, alleging that the defendants violated the law by manipulating the market to grossly inflate electricity prices. Named defendants in these lawsuits include Duke Energy Corporation and related entities along with other named sellers into the California market and numerous other unidentified defendants. Certain of these lawsuits were consolidated for hearing in state court in San Diego, California. In May 2002, the named defendants served a cross-claim on PNM. Duke Energy Corporation also cross-claimed against many of the other sellers into California. Duke Energy Corporation asked for declaratory relief and for indemnification for any damages that might ultimately be imposed on it. Several defendants removed the case to federal court in California. The federal judge has entered an order remanding the matter to state court, but the effect of that ruling has been stayed pending appeal. PNM has joined with other cross-defendants in motions to dismiss the cross-claim. In September 2005, PNM received an indication that Duke Energy Corporation intends to dismiss all cross-complaints against other sellers once its maximum liability is confirmed by final approval of its settlement in the class action lawsuits. The Company believes it has meritorious defenses to the cross-complaints filed against it, but cannot predict if settlement will result in dismissal of the cross-complaints or the outcome of this matter should the settlement not be approved.
In May 2005, the California Attorney General filed a lawsuit against PNM, PowerEx, a Canadian energy trading company, and the Colorado River Commission, in California state court alleging that PNM and PowerEx conspired to engage in unfair trade practices involving overcharges for electricity in violation of California state antitrust laws. The lawsuit claims that California customers were overcharged over a billion dollars and requests the court to award actual and treble damages. In June 2005, PowerEx filed a Notice of Removal that served to remove the lawsuit to the Federal District Court for the Eastern District of California. Both PNM and PowerEx filed motions to dismiss the lawsuit in June 2005, on grounds that the California Attorney General's lawsuit is preempted by federal law and even as to the allegations under California state law, failed to state a claim for which relief can be granted. PNM and PowerEx rely upon legal precedent in the Ninth Circuit holding that state antitrust claims asserting unlawful wholesale power prices under the Federal Power Act are preempted and a complainant's only remedy lies in FERC proceedings. Such proceedings are already currently pending at the FERC and the California Attorney General is already heavily involved in these proceedings. The Company's motion to dismiss is still pending as well as the California Attorney General's motion to remand the case back to state court, which both PNM and PowerEx have opposed. The Company cannot predict the outcome of this litigation, or whether the Company will be required to make any refunds or pay damages as a result of this litigation.
72
Block Forward Agreement Litigation
In February 2002, PNM was served with a declaratory relief complaint filed by the State of California in California state court. The state's declaratory relief complaint seeks a determination that the state is not liable for its commandeering of certain energy contracts known as "Block Forward Agreements". The Block Forward Agreements were a form of futures contracts for the purchase of electricity at below-market prices and served as security for payment by PG&E and SCE for their electricity purchases through the Cal PX. When PG&E and SCE defaulted on payment obligations incurred through the Cal PX, the Cal PX moved to liquidate the Block Forward Agreements to satisfy in part the obligations owed by PG&E and SCE. Before the Cal PX could liquidate the Block Forward Agreements, the State of California commandeered them for its own purposes. In March 2001, PNM and other similarly situated sellers of electricity through the Cal PX filed claims for damages with the California Victims Compensation and Government Claims Board (the "Victims Claims Board" for purposes of this discussion) on the theory that the state, by commandeering the Block Forward Agreements, had deprived them of security to which they were entitled under the terms of the Cal PX's tariff. The Victims Claims Board denied PNM 's claim in March 2002. PNM filed a complaint against the State of California in California state court in September 2002, seeking damages for the state's commandeering of the Block Forward Agreements and requesting judicial coordination with the state's declaratory relief action filed in February 2002 on the basis that the two actions raise essentially the same issues. The California state court judge delayed establishing a procedural schedule for the case pending a determination of the Cal PX's status in the litigation. The judge has since held that the Cal PX could represent the interests of Cal PX participants in the litigation. In March 2004, both the Cal PX and the State of California filed demurrers against each other's actions, alleging each other's actions failed to state a cause of action and that the issues raised in the other's case were identical to the issues raised in their own cases. In a hearing held in April 2004, the judge determined not to rule on the demurrers until the specific market participants named in the declaratory action proceeding affirmatively determined whether they would agree to be bound by any judgment reached in the Cal PX complaint action. As a result of the judge's order issued in May 2004, the various parties in the case were presented with a proposed stipulation under which the sellers would agree that the Cal PX would represent their interest in the proceedings, the sellers would agree to be bound by any judgment in the case, the sellers would dismiss their complaints against the State of California, and in turn, the State of California would dismiss its cross-complaints against the sellers, and the Cal PX would amend its complaint to indicate that it is bringing the lawsuit on behalf of the sellers. PNM agreed with the stipulation and executed the stipulation agreement. The Company cannot predict the outcome of the litigation involving the Cal PX and the State of California, or whether PNM will be awarded any damages as a result of the litigation.
In separate proceedings before the FERC involving the collection of costs associated with the Cal PX wind-up activities, the subject of the Block Forward Agreement litigation has become an element of the ongoing settlement discussions. If the terms of the settlement are accepted by the parties in the wind-up costs proceedings, California market participants,
73
including PNM, will have the option to opt-in to voluntarily agree to continue funding on a going-forward basis the expenses associated with the block forward agreement litigation. Alternatively, market participants could agree to take an assignment of the Cal PX's claim and they could then continue to prosecute the claim with the condition that any recovery that may ultimately be achieved would be deposited into a FERC account for distribution as the FERC deems appropriate. In the event that none of the parties opt-in to fund the litigation or no assignment of the claim is made, then the Cal PX must dismiss the claim with prejudice. The parties to the Cal PX wind-up costs proceedings at the FERC did include, as part of the settlement terms, the opt-in provisions for purposes of funding the Block Forward Agreement litigation and filed the settlement proposal containing such provisions in September 2005. In October 2005, the FERC issued its order accepting the Cal PX wind-up settlement, including the provisions setting out the opt-in settlement provisions for the Block Forward Agreement.
Wholesale Power Marketing Antitrust Suit
In June 2004, PNM received notice that PNM has been included in a list of 56 defendants that have been sued by the City of Tacoma Department of Public Utilities in federal district court in the State of Washington. PNM has been listed in a class of defendants referred to as the "Trading Defendants", who allegedly engaged in buying, selling and marketing power in California and other locations in the Western United States. The complaint alleges the Trading Defendants acted in concert among themselves and with "Non-Defendant Trading Co-Conspirators" that were engaged in conduct that amounted to market manipulations, which the complaint defines as a pattern of activities that had the purpose and effect of creating the impression that the demand for power was higher, the supply of power was lower, or both, than was in fact the case. The complaint identified specific conduct that allegedly amounted to market manipulations, including the submission of false information and misrepresentation regarding load schedules, bids, power supply, transmission congestion, source and destination of energy, the supply and provision of energy and ancillary services. The complaint alleged the activities of the Trading Defendants, along with "Generator Defendants", who are defined as generators who generated power for sale into California and other Western markets, and the co-conspirators, resulted in substantially increased prices for energy in the Pacific Northwest spot market in excess of what otherwise would have been the price absent such unlawful acts, in violation of antitrust laws. The complaint asserted damages in excess of $175.0 million from the multiple defendants. There have been three recent Ninth Circuit decisions that, collectively, appear to make Plaintiffs' case more difficult to prevail. As a result, PNM joined a motion to dismiss the City of Tacoma Department of Public Utilities complaint given Ninth Circuit precedent. In a decision issued in February 2005, the district court judge in the case granted defendants' motion to dismiss. As a result, the antitrust lawsuit against PNM filed by the City of Tacoma Department of Public Utilities was dismissed. In March 2005, the City of Tacoma Department of Public Utilities filed an appeal in the Ninth Circuit contesting the district court's decision to dismiss the complaint. PNM participated in the appeal in support of the dismissal and joined in defendants' brief filed in the Ninth Circuit, as well as a motion for summary affirmance. The appeal and defendants' motion for summary affirmance of the district court is
74
pending before the Ninth Circuit and the Company cannot predict the outcome of this appeal, or whether PNM will be required to make any refunds or pay damages as a result of this litigation.
FERC Rule Making
Over the past several years, the FERC has issued numerous rules that have impacted the wholesale energy business. The FERC is attempting to remedy what it sees as undue discrimination in the provision of interstate transmission services and to ensure just and reasonable rates for electric energy within and among regional power markets.
In addition, the FERC has issued final rules that have an impact on the wholesale energy business and participants in the wholesale energy markets, including PNM. In August 2003, the FERC issued Order 2003, which requires electric utilities that own or control electric transmission facilities to set out standard procedures and a standard agreement for interconnecting generators larger than 20 MW, and to make such revisions as necessary to its OATT to comply with the requirements of the new rule. PNM made its initial compliance filing in January 2004 and, in September 2004, PNM received notice that its revised tariff filing was accepted by the FERC. In December 2004, the FERC issued Order 2003-B, which provided additional clarification on certain matters and required additional modifications to the pro forma tariff. PNM joined an industry group requesting rehearing of Order 2003-B, and also separately filed its petition for rehearing of Order 2003-B, both of which are still pending before the FERC. In February 2005, PNM made its compliance filing pursuant to Order 2003-B. In March 2005, PNM received notice that its compliance filing was accepted by FERC. In July 2005 the FERC issued Order 2003-C, in which it affirmed, with certain clarifications, the fundamentals in the FERC Order 2003-B, and denied PNM's petition for rehearing. In addition, in May 2005, the FERC issued a rulemaking, designated as Order 2006, in which it established the requirement for public utilities to amend their OATTs to include the FERC's standardized procedures for interconnecting small generators, no larger than 20 MW. Order 2006 states that the OATTs of all non-independent transmission providers are deemed revised to include the procedures and no formal OATT amendment will be required until compliance is due in the FERC's rulemaking on electronic tariff filings, which is still pending.
In April 2004, the FERC announced the establishment of a new interim two-pronged market power screen to be applied in market based rate cases. In May 2004, the FERC issued procedural orders in pending market based rate application/renewal cases, including PNM's case, requiring the use of the new two-pronged interim screen and requiring PNM to make its revised market based rate filing by August 2004. In July 2004, the FERC issued an order affirming its interim two-pronged market screen test. PNM filed its triennial market power screen analyses in August 2004 utilizing the new two-pronged interim screen as required by the FERC's order. In its filing, PNM noted that, although fewer in nature due to recent system improvements, it continued to face transmission constraints in Northern New Mexico and would continue to abide by the cost-based rate limitation on transmission service during times
75
of transmission constraints for the Northern New Mexico market. PNM also noted that for the EPE control area, PNM's wholesale market share screen was slightly above 20% during two seasons. In October 2004, PNM made a supplemental filing utilizing more detailed load and generation data contained in EPE's market power screen filing, which resulted in PNM having a revised wholesale market share result below 20% for all seasons. In December 2004, the FERC issued its order in PNM's market based rate filing finding that the FERC is initiating a proceeding to determine if PNM's mitigation measure in Northern New Mexico is sufficiently adequate to prevent the exercise of market power. The FERC's order also required additional explanation of PNM's revised wholesale market share calculation. PNM filed a petition for rehearing contesting the FERC's findings regarding the EPE control area, and arguing that PNM lacks generation market power in Northern New Mexico given the transmission access available to transmission customers in that market and the pre-existing mitigation measure that FERC previously approved in 1996. The FERC also established that rates reviewed under this proceeding for transactions completed in these two markets would be subject to refund effective March 6, 2005. The Company is currently reviewing alternatives for resolution of the issues with the FERC. It is unclear whether resolution will include a requirement for refunds.
In February 2005, PNM made its compliance filing, in which the Company's expert presented various revised screen analyses for the EPE control area and concluded that the FERC should continue to permit PNM to make sales at market-based rates in that control area. The analyses showed that the screen failures disappear when the input data reflect the realities of economic and physical conditions in the Southern New Mexico market. PNM was of the view that the screen failure scenarios do not warrant the conclusion that PNM possesses generation market power in EPE's control area.
PNM's expert further concluded that the FERC should continue to permit PNM to make sales at market-based rates in PNM's Northern New Mexico control area, subject to the existing mitigation provision contained in PNM's market-based sales tariff. PNM's expert concluded that PNM does not have the potential to exercise generation market power because customers enjoy access to robust markets during the hours that concerned the FERC, and given that the pre-existing mitigation would prevent any exercise of generation market power in the event of transmission constraints. PNM's expert also concluded that, if the FERC determines that PNM should not be permitted to sell at market-based rates in its Northern New Mexico control area, the FERC nevertheless should permit PNM to sell at market-based rates at San Juan because San Juan is outside the transmission constraint path. In March 2005, EPE filed a motion in the proceeding expressing concern that PNM may have market power in the Southern New Mexico market and requesting the FERC to impose a price mitigation mechanism for PNM sales to EPE in Southern New Mexico. PNM filed its response contesting EPE's claim that PNM has market power in the Southern New Mexico market and opposing EPE's proposed mitigation measure. PNM, in April 2005, also filed a motion for appointment of a settlement judge in an effort to reach resolution on the issues pending in the proceeding.
In April 2005, the FERC issued an Order denying PNM's petition for rehearing regarding the FERC's finding that the existing mitigation measure for the Northern New Mexico control area was insufficient; rejecting PNM's February 2005 compliance filing as to both the Northern and Southern New Mexico control areas and requiring PNM to submit a compliance filing containing one of the alternatives listed in the Order; and denying PNM's motion for assignment of a settlement judge. The FERC's Order also clarified that market based sales made at SJGS are sales made within PNM's Northern control area and are subject to these proceedings. Also, in June 2005, PNM filed a petition for judicial review of the FERC's December 2004 and April 2005 orders in the United States Court of Appeals for the District of Columbia Circuit. In its appeal, PNM requests the court to review the legality of the FERC's orders. In July 2005, PNM made its compliance filing at the FERC. The filing indicated that, as a result of the completion of its analysis pursuant to the FERC's order, PNM did show failures in its own control area, but did not show failures in the EPE control area, with the exception of one measure. The Company maintained its position that when the historical data is considered, it is clear that PNM does not possess generation market power in either the PNM or EPE control area destination markets and it should maintain its market-based sales authority in those markets. In the event the FERC does not so find, PNM also proposed mitigation measures in both the PNM and EPE control area destination markets that will be applicable during the limited time periods when the failures occurred. EPE filed comments in response to PNM's filing in August 2005, to which PNM filed a subsequent reply. EPE then proceeded to file an objection to PNM's response in September 2005. The Company cannot predict the outcome of the additional FERC proceedings on the Company's financial position or results of operations; however, should the FERC determine that PNM has generation market power in these two markets, PNM could continue to make sales at cost-based or otherwise mitigated rates and thus not have future revenues subject to refund in this matter. The Company also cannot predict the outcome of the court appeal of the FERC's prior orders.
In July 2005, the FERC issued an order terminating its proceeding on standard market design, stating that since issuance of the standard market design notice of proposed rulemaking, the electric industry has made significant progress in the development of voluntary RTOs/ISOs which has allowed interested parties, through region-specific proceedings, to shape the development of independent entities to reflect the needs of each particular region. In September 2005, the FERC issued a Notice of Inquiry on Preventing Undue Discrimination and Preference in Transmission Services seeking information from the industry regarding the provisions of the OATT for possible revision in a future rulemaking. The Company intends to monitor and participate in this FERC Notice of Inquiry, as well as the future rulemakings arising out of the matters addressed in this docket.
As discussed above in the PNM "SESCO Matter," in October 2003, the TCEQ notified approximately 50 companies, including TNMP, that releases of hazardous substances had been
77
documented from a site owned and operated by SESCO. TNMP purchased transformers from the vendor and also sent some transformers to the vendor for repair and/or disposal. The owner and operator of the site have filed for bankruptcy and the site is under the control of the bankruptcy trustee. In August 2004, 15 of the companies identified by TCEQ as potentially responsible parties, including TNMP, formed the initial Working Group to manage the remediation efforts and determine the allocation of responsibility among the potentially responsible parties. Common counsel was recently hired to represent the common interests of the members of the Working Group. The Working Group's investigation into persons and entities that sent transformers and other equipment to SESCO is ongoing. In addition, the Working Group sent a request for proposal for an environmental contractor to perform a remedial investigation and assessment study for the SESCO site and is currently reviewing responses. TNMP is still investigating its role in the matter, and is unable to predict the outcome at this time.
TNMP True-Up Proceeding
In July 2004, the PUCT issued its first order in TNMP's stranded cost true-up proceeding. The purpose of the true-up proceeding was to quantify and reconcile the amount of stranded costs that TNMP may recover from its transmission and distribution customers. The PUCT decision established $128.4 million as TNMP's stranded costs and allowed TNMP to recover $87.3 million of the $266.5 million that TNMP requested for its true-up balance.
In August 2004, TNMP filed a motion for rehearing of the PUCT decision. In October 2004, the PUCT denied all of TNMP's motions for rehearing except for an issue related to a June 2004 Texas Supreme Court ruling that addressed recovery of carrying charges on recoverable stranded costs back to January 1, 2002, the date that competition began in Texas.
In March 2005, the PUCT administrative law judge issued a proposal for decision on the remanded interest issue. The decision recommended that TNMP be allowed recovery of $41.7 million of carrying charges on stranded costs for the period January 1, 2002 through July 21, 2004, and was consistent with amounts recorded by TNMP. In accordance with provisions within SFAS No. 92, "Regulated Enterprises - Accounting for Phase-In Plans" ("SFAS 92"), TNMP recorded $27.2 million of carrying charges to the income statement for the period January 1, 2002 through July 21, 2004, in the fourth quarter of 2004. TNMP was limited in its recognition for income statement purposes to only the debt related portion of the carrying charges, and TNMP was prohibited from income statement recognition of the equity portion of the carrying charges until the actual receipt of those amounts from customers.
In April 2005, the PUCT announced its decision that TNMP will be allowed to recover interest at a lower rate than the administrative law judge adopted. The lower rate results in $39.2 million of carrying costs on stranded costs for the period January 1, 2002 through July 21, 2004. The PUCT rejected the administrative law judge proposal that TNMP be allowed to utilize the weighted average cost of debt inherent in its 2000 Unbundled Cost of Service filing.
78
Instead, the PUCT utilized TNMP's actual weighted average cost of debt as of December 31, 2001. Accordingly, TNMP reduced the carrying costs for income statement recognition for the period January 1, 2002 through July 21, 2004 by $4.1 million, and reduced the total carrying charges for income statement recognition for the period January 1, 2002 through December 31, 2004 by $4.7 million during the first quarter of 2005. TNMP's accrual for 2005 carrying charges is also based on the PUCT ruling. As of September 30, 2005, the accrual was $55.8 million and the equity portion of the carrying charges on stranded costs that TNMP was prohibited from recognition through the income statement until actual receipt from customers totaled $23.8 million.
In July 2005, the PUCT confirmed TNMP's calculation of the carrying costs on stranded costs in a written order. TNMP and other parties have filed petitions for judicial review of the July PUCT order.
(9) Regulatory and Rate Matters
Energy Policy Act
In September 2005, President George W. Bush signed the Energy Policy Act of 2005 into law. Implementation of various portions of the law requires the issuance of rules by the FERC. The FERC has initiated a number of rulemakings, among them a proposed rulemaking to implement the reliability provisions of the Energy Policy Act of 2005; a proposed rulemaking to revise the criteria for what will be considered a new cogeneration qualifying facility under PURPA; a notice of proposed rulemaking to implement the PUHCA repeal provisions; a proposed rulemaking implementing the market manipulation prohibition; and a proposed rulemaking to implement the merger review provisions. In addition the FERC has asked for comments on whether or not it should use its Federal Power Act authority to impose additional restrictions regarding public utility holding company systems. Additional rulemakings are expected. The Company will continue to monitor, and participate in as appropriate, the FERC and other proceedings involving implementation of Energy Policy Act of 2005, in order to assess the implications of the new law and rules on its operations.
Retail Competition
As discussed in Note 1, the Texas electricity market has been open to retail competition since January 1, 2002. In accordance with Senate Bill 7, TNMP provides transmission and distribution services at regulated rates to various retail electric providers that, in turn, provide retail electric service within TNMP's Texas service area. First Choice, TNMP's affiliated retail electric provider, performs activities related to the sale of electricity to retail customers in Texas.
On June 1, 2004, several changes to customer protection rules in Texas became effective. Of the changes, the rules related to disconnection for non-payment and the required amount of
a customer deposit is having the greatest impact on First Choice. The new rule for disconnection for non-payment states that if a customer does not make a payment or payment arrangement until after the final due date specified in the disconnect notice, the retail electric provider is allowed to disconnect the customer. The previous rule only allowed the retail electric provider to terminate service and transfer the customer to the retail electric provider that was affiliated with the customer's transmission and distribution service provider, or to the provider of last resort for non-payment. The new rule for the required amount of deposit states that the deposit shall not exceed the greater of one-fifth of the estimated annual billing or the sum of the next two month's estimated billings. The previous rule stated that the deposit could not exceed the greater of one-sixth of the estimated annual billing or the sum of the next two month's estimated billings.
First Choice is responsible for energy supply related to the sale of electricity to retail customers in Texas. Senate Bill 7 contains no provisions for the specific recovery of fuel and purchased power costs, although First Choice can request that the PUCT change the price-to-beat fuel factor twice a year to recognize changes in natural gas prices. The rates charged to new customers acquired by First Choice outside of TNMP's service territory are not regulated by the PUCT, but are negotiated with each customer. As a result, changes in fuel and purchased power costs will affect First Choice's operating results.
Price-to-Beat Fuel Factor
At its final open meeting for October 2005, the PUCT approved First Choice's request to increase its price-to-beat fuel factor. First Choice estimates that the increase in the price-to-beat fuel factor will increase 2005 revenues by approximately $9.4 million, based on an increase in the fuel factor of 41.33% from October 29 through December 31, 2005. The price-to-beat fuel factor will automatically increase again to 45.15% on January 1, 2006.
If natural gas markets decline from current levels, First Choice will file a request to reset its price-to-beat fuel factor shortly before the PUCT issues an order in TNMP's 60-day rate review case. Resulting rates will be effective within 30 days of a final order in TNMP's 60-day rate review.
Price-to-Beat Base Rate Reset
First Choice is required to make a filing to reset its price-to-beat base rates no later than 30 days after TNMP files its 60-day rate review. First Choice will file its price-to-beat base rate case in early December 2005. First Choice's resulting rates will take effect no later than 30 days following a final order on TNMP's 60-day rate review. First Choice will request that the PUCT recognize in its new price-to-beat base rates the TNMP rate reduction and the synergy savings credit provided for in the acquisition stipulation.
80
Energy Agreement
In 2003, First Choice and Constellation executed a power supply agreement that resulted in Constellation being the primary supplier of power for First Choice's customers through the end of 2007. Additionally, Constellation has agreed to supply power in certain transactions under the agreement beyond the date when that commitment expires.
In 2004, FCPSP, a bankruptcy remote entity, was created pursuant to the agreement with Constellation to hold all customer contracts, wholesale power contracts, and certain natural gas contracts previously held by First Choice. Constellation received a lien against the assets of FCPSP to cover the settlement exposure and the mark-to-market exposure rather than requiring FCPSP to post alternate collateral for the purchase of power supply. In addition, FCPSP is restricted by covenants that limit the size of FCPSP's unhedged market positions and require that sales by FCPSP retain a positive retail margin. The agreement does not, however, permit Constellation to demand additional collateral irrespective of its credit exposure under the agreement. If, however, a change in electricity or gas forward prices increases Constellation's credit exposure to FCPSP beyond a limit based on Constellation's liens in cash and accounts receivable, Constellation will have no obligation to supply additional power to customers of FCPSP unless FCPSP provides letters of credit or other collateral acceptable to Constellation, and FCPSP will be constrained in its ability to sign up additional customers until that credit shortfall is corrected.
FCPSP may terminate the agreement upon 30 days' prior written notice to Constellation for any reason, but the agreement and all liens securing the agreement remain in effect with respect to transactions entered into prior to the termination until both parties have fulfilled all of their obligations with respect to such transactions or such transactions have been terminated for default or reasons related to regulatory changes.
Global Electric Agreement
The Global Electric Agreement was signed in 2003. The Global Electric Agreement provided for the repeal of a majority of the Restructuring Act, a fixed rate path, procedures for PNM's participation in unregulated generating plant activities and other regulatory issues. In accordance with this rate path, PNM reduced its retail rates by 2.5% in September 2005. The rate path is effective through December 31, 2007, at which time rates are subject to review by the NMPRC. As a result of the repeal of the Restructuring Act, PNM re-applied the accounting requirements of SFAS 71, as amended, "Accounting for the Effects of Certain Types of Regulation," to its regulated generation activities.
Transmission Rate Case
In March 2005, PNM filed a notice with the FERC to increase its wholesale electric transmission revenues by approximately $7.8 million annually. If approved, the rate increase would apply to all of PNM's wholesale electric transmission service customers, which includes other utilities, electric co-operatives and entities that use PNM's transmission system to transmit power at the wholesale level. The proposed rate increase would not impact PNM's retail customers. In May 2005, the FERC issued an order in the case suspending the new rates for the standard five-month period and made the new rates effective November 1, 2005, subject to refund. Additionally, pursuant to the FERC's order, a settlement judge was assigned to the case and an initial settlement conference was held in July 2005. PNM has been engaged in providing information requested by the parties in an effort to facilitate settlement in the case. Additional settlement discussions have been held with FERC staff and the parties to the proceeding. An additional conference in front of the FERC settlement judge has been scheduled for November 2005. The Company is unable to predict the outcome of the rate proceeding or if the parties will be able to reach a settlement in the case.
Complaint Against Southwestern Public Service Company
In September 2005, PNM filed a complaint under the Federal Power Act against Southwestern Public Service Company. PNM believes that through its fuel charge adjustment clause, Southwestern Public Service Company has been overcharging PNM for deliveries of energy under three contracts, and continues to do so. PNM requested that the FERC investigate Southwestern Public Service Company's charges for the period 2001 through 2004. Charges for 2005 are being addressed in a separate case currently pending before the FERC, in which PNM is an intervenor in the case. PNM's complaint also alleges that Southwestern Public Service Company's rates for interruptible power sales are excessive and requested that the FERC set a refund effective date of September 13, 2005 for these rates. PNM cannot predict the outcome of this complaint at the FERC.
60-Day Rate Review
TNMP is required to make a 60-day rate review filing by November 5, 2005. TNMP's case will establish a competition transition charge for recovery of the true-up balance. TNMP's competition transition charge will take effect no later than 30 days following a final order on TNMP's 60-day rate review.
Final Fuel Reconciliation
In January 2004, the PUCT issued an order that disallowed $15.7 million of fuel and energy related purchased power costs that TNMP incurred in 2000 and 2001, prior to retail
82
competition. TNMP recorded the $10.1 million net of tax effect of the disallowance in the fourth quarter of 2003, and subsequently appealed the PUCT decision to the district court. In June 2005, the District Court affirmed the PUCT order, effectively denying TNMP's appeal.
(10) Variable Interest Entities
FASB Interpretation No. 46, "Consolidation of Variable Interest Entities" (Revised December 2003) ("FIN 46R"), became effective January 1, 2004 for those entities considered to be special purpose entities, and March 31, 2004 for others. Under the model for consolidation promulgated by FIN 46R, a PPA may qualify as a variable interest if its terms expose the purchaser to variability in supply or operating costs and the contract is for a significant portion of the entity's generating capacity. PNMR evaluated its PPAs under the provisions of FIN 46R and determined that one purchase contract entered into prior to December 31, 2003 qualifies as a variable interest. PNMR was unable to obtain the necessary information needed to determine if PNMR was the primary beneficiary and if consolidation was needed despite efforts including a formal written request to the operator of the entity supplying power under the PPA. The operator cited legal and competitive reasons for refusing to provide the information.
This variable interest PPA is a contract to purchase 132 MW of capacity and energy expiring in June 2020. The contract contains a fixed capacity charge, a fixed O&M charge, and a variable energy charge that subjects PNM to the changes in the cost of fuel and O&M. For the three months ended September 30, 2005 and 2004, the capacity and O&M charge was $1.8 million and $1.8 million, respectively, and the energy charges were $0.2 million and $0.4 million, respectively. For the nine months ended September 30, 2005 and 2004, the capacity and O&M charge was $5.1 million and $4.4 million, respectively, and the energy charges were $0.8 million and $0.8 million, respectively. The contract is for the full output of a specific gas generating plant and is currently accounted for as an operating lease by PNM. Under this contract PNM is exposed to changes in the costs to produce energy and operate the plant.
PNMR also has interests in other variable interest entities created before January 31, 2003, for which PNMR is not the primary beneficiary. These arrangements include PNMR's investment in a limited partnership and certain PNM leases. The aggregate maximum loss exposure at September 30, 2005 that PNMR could be required to record in its income statement as a result of these arrangements totals approximately $5.3 million. The creditors of these variable interest entities do not have recourse to the general credit of PNMR in excess of the aggregate maximum loss exposure.
(11) Related Party Transactions
PNMR, PNM and TNMP are considered related parties as defined in SFAS No. 57, "Related Party Disclosures." Since TNMP became a related party effective on the date of PNMR's
83
acquisition of TNP, the reported amounts for TNMP reflect the period from June 6, 2005 through September 30, 2005.
PNMR Services Company provides corporate services to PNMR and its subsidiaries including PNM, Avistar, Inc., TNP, TNMP and First Choice per shared services agreements. These services are billed at cost on a monthly basis and allocated to the subsidiaries.
PNM and TNMP have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of power and transmission purchases by TNMP from PNM. Transactions between affiliates are reported separately on their financial statements, but are eliminated in the consolidation of PNMR's financial statements.
Pursuant to agreement, PNM has issued a promissory note for $20.0 million to PNMR payable on or before September 30, 2006. Under the agreement, PNM agrees to pay all applicable interest on the outstanding balance at the interest rates provided in the agreement. As of September 30, 2005 there is no outstanding balance on the promissory note.
PNM sells electricity and energy-scheduling services to TNMP under a long-term wholesale power contract. PNM also sells transmission services to TNMP and TNMP provides transmission services to PNM under an agreement.
84
The tables below describe the nature and amount of transactions PNM has with PNMR and TNMP. Since TNMP became a related party effective on the date of PNMR's acquisition of TNP, the reported amounts for TNMP reflect the period from June 6, 2005 through September 30, 2005.
Three Months
Nine Months
Ended September 30,
PNMR Transactions With PNM
Shared services billings from PNMR to PNM
$30,076
$24,702
$81,321
$82,020
Shared services receivable/payable as of
$ 9,528
$31,875
PNM Transactions with TNMP
Electricity and energy scheduling service
billings from PNM to TNMP
$11,043
$13,947
Electricity and energy scheduling services
receivable as of September 30, 2005
Transmission billings from PNM to TNMP
$ 554
$ 694
Transmission charges receivable as of
Transmission billings to PNM from TNMP
$ 90
$ 101
Transmission charges payable as of
TNMP purchases all the electricity for its New Mexico customers' needs (except for one major customer) and energy-scheduling services under the long-term wholesale power contract with PNM described above. TNMP also purchases transmission services from PNM in New Mexico. Additionally, TNMP provides transmission services to PNM in New Mexico.
Effective with the close of the acquisition of TNP on June 6, 2005, all TNMP employees who were providing corporate support to TNP and First Choice became employees of PNMR Services Company. PNMR Services Company provides corporate services to TNMP per a shared services agreement.
85
TNMP Transactions With PNM
billings to TNMP from PNM
payable of September 30, 2005
Transmission billings to TNMP from PNM
Transmission billings from TNMP to PNM
TNMP Transactions with PNMR
Shared services billings to TNMP from PNMR
$ 3,755
$ 4,900
Shared services payable as of
$ 1,941
86
(12) New Accounting Pronouncements
In June 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error Corrections" ("SFAS 154"). SFAS 154 applies to all voluntary changes in accounting principle, and changes the requirements for accounting for and reporting of a change in accounting principle. SFAS 154 requires retrospective application to prior periods' financial statements of a voluntary change in accounting principle unless it is impracticable. Prior accounting rules required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. SFAS 154 will improve financial reporting because its requirements enhance the consistency of financial information between periods. SFAS 154 requires that a change in the method of depreciation, amortization, or depletion for long-lived, non-financial assets be accounted for as a change in accounting estimate that is affected by a change in accounting principle. Previously, such a change was reported as a change in accounting principle. SFAS 154 is effective for accounting changes and corrections of errors made beginning January 1, 2006. The Company does not expect that the adoption will have a significant effect on its results of operations or financial condition when adopted.
In March 2005, the FASB issued Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations" ("FIN 47"). FIN 47 states that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation (ARO) when incurred if the liability's fair value can be reasonably estimated. The Interpretation clarifies when an entity would have sufficient information to reasonably estimate the fair value of the ARO. An ARO would be reasonably estimable if: (a) it is evident that the fair value of the obligation is embodied in the acquisition price of the asset, (b) an active market exists for the transfer of the obligation, or (c) sufficient information exists to apply an expected present value technique. Upon application of FIN 47, amounts will be measured using current information, assumptions and interest rates. The recognized asset retirement cost will be measured as of the date the ARO was incurred. Cumulative accretion and accumulated depreciation will be recorded for the time period from the date the liability would have been recognized had the provisions of this Interpretation been in effect when the liability was incurred to the date of adoption of this Interpretation. The cumulative effect of initially applying FIN 47 should be recognized as a change in accounting principle. FIN 47 will be effective for the year ending December 31, 2005. The Company is currently evaluating the impact of adopting FIN 47 and is unable to predict its impact on the Company's operating results and financial position at this time.
87
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following Management's Discussion and Analysis of Financial Condition and Results of Operations for PNMR, PNM and TNMP is presented both on a combined basis as applicable, and on a separate basis. For discussion purposes, this report will use the term "Company" when discussing matters of common applicability to PNMR, PNM and TNMP. Discussions regarding specific contractual obligations generally reference the company that is legally obligated. In the case of contractual obligations of PNM and TNMP, these obligations are consolidated with PNMR and its subsidiaries under GAAP.
The Company is positioned as a merchant utility, primarily operating as a regulated energy service provider. The Company is engaged in the sale and marketing of electricity in the competitive wholesale energy marketplace. In addition, through First Choice, the Company is a retail electric provider in Texas under legislation that established retail competition. As a utility, PNM has an obligation to serve its customers under the jurisdiction of the NMPRC while TNMP operates under the jurisdiction of the PUCT in Texas and the NMPRC in New Mexico.
In conjunction with the TNP acquisition, management changed its business segment reporting. As it currently operates, PNMR's principal businesses include regulated operations and unregulated operations. As required by SEC regulations, PNMR filed a Current Report on Form 8-K on September 26, 2005 that conformed its presentation of segment information in the 2004 Annual Report on Form 10-K to reflect the revised segment presentation.
Regulated Operations
The regulated operations strategy is directed at supplying reasonably priced and reliable energy to retail customers through customer-driven operational excellence, high quality customer service, cost efficient processes, and improved overall organizational performance.
PNM Electric is an integrated electric utility that consists of generation, transmission and distribution of electricity for retail electric customers in New Mexico and transmission of sales to third parties as well as to PNM Wholesale and TNMP. PNM Electric provides retail electric service to a large area of north central New Mexico, including the cities of Albuquerque and Santa Fe, and certain other areas of New Mexico. Customer rates for retail electric service are set by the NMPRC based on the provisions of the Global Electric Agreement. (See Note 9 - "Regulatory and Rate Matters - Global Electric Agreement," in the Notes to Consolidated Financial Statements.) PNM Electric owns or leases transmission lines, interconnected with other utilities in New Mexico, south and east into Texas, west into Arizona, and north into Colorado and Utah.
PNM Gas distributes natural gas to most of the major communities in New Mexico, including two of New Mexico's three largest metropolitan areas, Albuquerque and Santa Fe. The customer base for PNM Gas includes both sales-service customers and transportation-service customers. PNM Gas operates under a purchase gas adjustment clause that allows it to purchase natural gas in the open market and resell it at cost to its distribution customers. As a
result, increases or decreases in gas revenues resulting from wholesale gas price fluctuations do not impact PNMR's or PNM's consolidated gross margin or earnings.
TNMP Electric is a regulated utility operating in Texas and New Mexico. In Texas, TNMP provides regulated transmission and distribution services under TECA. In New Mexico, TNMP provides integrated electric services that include the transmission, distribution, purchase and sale of electricity to its New Mexico customers as well as transmission to third parties and to PNM. TNMP's Texas and New Mexico operations are subject to traditional cost of service regulation.
Unregulated Operations
PNM Wholesale is engaged in the generation and sale of electricity into the wholesale market based on two product lines that include long-term contracts and short-term sales. PNM Wholesale also sells transmission services to TNMP. The source of these sales is supply created by selling the unused capacity of jurisdictional assets as well as the capacity of PNM's wholesale plants excluded from retail rates. Both regulated and unregulated generation is jointly dispatched in order to improve reliability, provide the most economic power to retail customers and maximize profits on any wholesale transactions. The strategy utilized by the Company calls for net asset-backed energy sales supported by long-term contracts into the wholesale market, whereby the Company's aggregate net open forward electric sales position, including short-term sales and long-term contracts, is covered by its forecasted excess generation capacity. Management actively monitors the net asset-backed sales by the use of stringent risk management policies. The Company's future growth plans call for approximately 75% of its new generation portfolio to be committed through long-term contracts as required by the Global Electric Agreement. Growth will be dependent on market development and on the Company's ability to generate funds for the future expansion. The Company will continue to operate in the wholesale market and seek reasonably priced asset additions. Expansion of the Company's generating portfolio will depend on the Company's ability to acquire favorably priced assets at strategic locations and to secure long-term commitments for the purchase of power from the acquired plant capacity.
First Choice is a certified retail electric provider operating in Texas, which allows it to provide electricity to residential, small and large commercial, industrial and institutional customers. First Choice performs all activities in Texas with Texas retail customers, including acquiring new retail customers, setting up retail accounts, handling customer inquiries and complaints, and acting as a liaison between the transmission and distribution companies and retail customers. First Choice was organized in 2000 to act as TNMP's affiliated retail electric provider, as required by TECA.
89
Corporate and Other
PNMR was established as the holding company in 2001. On December 30, 2004, PNMR became a registered holding company under PUHCA. PNMR also created a new subsidiary called PNMR Services Company, which began operating on January 1, 2005, subject to final approval of a services company application filed with the SEC in January 2005.
The comprehensive energy legislation enacted in August 2005, will result in the repeal of PUHCA on a delayed basis. PNMR is in the process of evaluating the effects of that repeal, along with the other provisions of the legislation.
PNMR performed substantially all of the corporate activities of PNM from 2001 to 2004. These activities were billed to PNM on a cost basis to the extent they were for the corporate management of PNM and were allocated to the business units. The services functions previously performed by PNMR were assumed by PNMR Services Company effective January 1, 2005.
TNMP provided First Choice and TNP with corporate support services under a shared services agreement with First Choice and a similar agreement with TNP. These services were billed at TNMP's cost and, in return, TNP and First Choice compensated TNMP for the use of the services. These agreements were in effect through June 6, 2005 when they were replaced by a new service arrangement.
Effective with the acquisition of TNP on June 6, 2005, (see Note 2 - "TNP Acquisition," in the Notes to the Consolidated Financial Statements) all TNMP employees who were providing corporate support to TNP and First Choice became employees of PNMR Services Company. PNMR Services Company provides corporate services to PNMR and its subsidiaries including PNM, Avistar, Inc., TNP, TNMP and First Choice based on shared services agreements. These services are billed at cost on a monthly basis and are allocated to PNMR and its subsidiaries.
The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes contained herein. Trends and contingencies of a material nature are discussed to the extent known. Refer to "Disclosure Regarding Forward Looking Statements" and "Risk Factors" at the end of this Item 2.
COMPETITIVE STRATEGY
The Company's vision is to "Build America's Best Merchant Utility." To achieve this objective, management intends to:
Grow Regulated and Unregulated Operations. The Company intends to grow both its retail and wholesale business by expanding its current operations and by acquiring additional value-enhancing assets. As evidenced by the Luna and TNP acquisitions, the Company intends to continue to grow its revenues by expanding its geographic coverage in the Southwest, a region which not only exhibits rapid customer and load growth, but which the Company knows well. The Company plans to focus on best practices in integrating its acquisitions to create a stronger presence in the Southwest market. The Company also intends to increase its presence in the
90
Southwest market by buying additional generating resources and selling power from those resources through long-term contracts. In October 2005, PNM entered into a 150 MW long-term sale contract with APS that begins in June 2007. In addition, the Company expects that the acquisition of First Choice as part of the TNP acquisition will provide a solid foundation for entry into the competitive retail market in Texas. In addition, PNMR intends to continue to provide energy and technology related services through its wholly owned subsidiary, Avistar, Inc.
Acquire Additional Generating Assets in the Southwest Region. The Company intends to enhance and diversify its presence in the Southwest region through the acquisition of quality generation assets to serve the Company's retail and wholesale load while maintaining diversity of fuel mix. The Company plans to increase long-term sales contracts in tandem with increases in its generation capacity. The Company expects to do this through the addition of gas-fired generation plants and the acquisition of coal-fired facilities, the acquisition or development of renewable or clean technology resources and/or the use of long-term purchase contracts for power. As in the past, the Company intends to continue a disciplined approach to any acquisition, to match acquisitions to demand and to hedge capacity with long-term contracts.
Maintain Prudent Cost Controls. Management maintains cost control procedures for PNMR and its subsidiaries.
Continue to Improve Credit Strength and Reduce Cost of Capital. A high priority and long-term commitment is to maintain the Company's investment grade rating in any type of regulatory, natural gas or electricity price scenario. The Company believes TNP offers an opportunity to derive additional value through the stronger credit profile of the combined entity. In addition, the Company expects lower TNP financing costs, through the refinancing of TNP's relatively high-cost capital. In conjunction with the acquisition of TNP, on June 6, 2005, PNMR made an equity investment of approximately $110.5 million in TNP, which TNP used to repay in full amounts owing under TNP's credit agreement. In addition, in July 2005, PNMR provided funds to TNP to enable TNP to redeem its preferred stock and senior notes. See "Financing Activities - PNMR" below in "Liquidity and Capital Resources" for further details of this transaction.
Commitment to Corporate Citizenship. The Company is committed to its guiding principle, "Do the Right Thing." This commitment serves as the cornerstone of the Company's ethics and compliance efforts and underscores its effort to ensure that dealings with customers, employees, shareholders and business partners are above reproach. This is evidenced by the Company's environmental sustainability program with aggressive five-year goals for reducing water usage, improving air quality, reducing waste streams and becoming a leader in the development of renewable energy.
ACQUISITION
Acquisition of TNP. On June 6, 2005, PNMR acquired all of the outstanding common shares of TNP, including its principal subsidiaries, TNMP and First Choice. The results of TNP's operations have been included in the consolidated financial statements of PNMR from that date.
91
PNMR acquired TNP in order to complement its existing New Mexico electric operations and to expand into the retail and wholesale markets in Texas.
The aggregate purchase price was $1,277 million, including a payment to the previous owner of $175.0 million consisting of $87.6 million of cash and common stock valued at $87.4 million. In addition, the aggregate purchase price included $1,034 million of TNP debt and preferred stock and incurred transaction and other costs of $67.7 million. The value of the 4,326,337 common shares issued was determined based on $20.20 per common share as provided for in the Stock Purchase Agreement. The purchase price was based on an estimated purchase price in accordance with the Stock Purchase Agreement, dated as of July 24, 2004 by and between PNMR and SW Acquisition. PNMR obtained, or is in the process of obtaining, valuations of acquired property and intangible assets; thus, the allocation of the purchase price is subject to adjustment and will be finalized within one year of the acquisition.
Pursuant to the Stock Purchase Agreement, PNMR provided SW Acquisition its proposed final purchase price, reflecting a reduction from the estimated purchase price of approximately $37 million. SW Acquisition has objected to PNMR's proposed final purchase price. There is a mechanism established in the Stock Purchase Agreement for resolving disputes regarding the final purchase price. However, in August 2005, SW Acquisition filed a petition against PNMR in Texas state district court, in which SW Acquisition alleged, among other things, that PNMR had breached the Stock Purchase Agreement. The petition seeks a declaration of the parties' rights and duties under the Stock Purchase Agreement, including the final purchase price, and also seeks damages in an unspecified amount. In September 2005, PNMR filed an answer to the petition generally denying SW Acquisition's claims and a counterclaim seeking damages for SW Acquisition's breaches of contract including its early termination of the negotiation period provided for in the Stock Purchase Agreement and its breach of the provisions in the Stock Purchase Agreement regarding alternate dispute resolution. PNMR also filed a motion to compel arbitration consistent with the Stock Purchase Agreement and a motion for a preliminary injunction that would force SW Acquisition to choose an accountant to resolve the purchase price dispute. The court has scheduled a hearing on the motion to compel arbitration for November 2005. PNMR believes the SW Acquisition petition is without merit and intends to vigorously defend itself and otherwise protect its rights under the Stock Purchase Agreement. See Note 2 - "TNP Acquisition," in the Notes to Consolidated Financial Statements.
Reference is made to the Current Reports on Forms 8-K/A filed by PNMR on August 2, and September 27, 2005, in connection with the acquisition of TNP. The August 2 Form 8-K/A incorporates by reference the audited and unaudited financial statements of TNP required by Form 8-K Item 9.01 (a) and the August 2 and September 27 Forms 8-K/A include the pro forma financial information required by Form 8-K Item 9.01 (b).
92
OVERALL OUTLOOK
The Company experienced lower than expected earnings growth in the first nine months of 2005 primarily due to unexpected plant outages, the extension of planned outages, the acceleration of a scheduled outage and other non-recurring charges for refinancing and TNP acquisition integration costs. The Company expects to incur lower plant operating costs and recover a portion of the reduction in revenue related to the accelerated outage schedule in the fourth quarter of 2005 when the SJGS Unit 4 planned outage would otherwise have occurred. In addition, the Company expects to experience added earnings growth resulting from the acquisition of TNP.
The Company expects that the TNP acquisition will be accretive to earnings in the first full year of operation after the transaction is completed. This expectation is based on certain assumptions, including assumptions related to interest rates and market prices for power, among other things. In recent months, the market price of natural gas across the United States has increased significantly, due to a hot 2005 summer, which led to more demand from natural gas-fired power plants, as well as due to the hurricanes in the Gulf Coast region of the United States. The Company cannot predict what impact the increase in market prices for natural gas will have on its future results of operations; however the Company does anticipate an increase in O&M costs, primarily related to bad debts, due to the increases in gas prices.
RESULTS OF OPERATIONS
Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004
PNMR's net earnings for the three months ended September 30, 2005 were $28.5 million or $0.41 per diluted share of common stock, compared to $27.4 million or $0.45 per diluted share of common stock in the three months ended September 30, 2004. The decrease in earnings per share was driven primarily by acquisition related costs and other non-recurring charges of $3.4 million, net of income taxes, which consisted of acquisition integration costs of $2.6 million and TNP debt refinancing costs of $0.8 million. In addition, PNM experienced below normal levels of plant performance due to unexpected plant outages and the extension of planned plant outages, which reduced the amount of electricity PNM sold in the wholesale market and forced PNM to purchase power to meet jurisdictional and contractual wholesale needs. In addition, the margin on fixed-price contracts decreased, as increases in purchased power prices that were driven by increasing fuel prices were not able to be passed on to customers with fixed sales prices. These decreases to net earnings were partially offset by the addition of TNP operations for the three months ended September 30, 2005.
The following discussion is based on the methodology that management uses for making operating decisions and assessing performance of its various business activities. See Note 3 - "Segment Information," in the Notes to the Consolidated Financial Statements for additional information regarding these results and the consolidated financial statements.
93
In addition, adjustments related to EITF Issue 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not Held for Trading Purposes," are excluded. This accounting pronouncement requires a net presentation of realized gains and losses for certain non-trading derivatives. Management evaluates PNM Wholesale on a gross presentation basis due to its primarily net-asset-backed marketing strategy and the importance it places on PNM's ability to repurchase and remarket previously sold capacity.
Corporate costs, income taxes and non-operating items are discussed on a consolidated basis for PNMR and are in conformity with the presentation in the PNMR consolidated financial statements.
The table below sets forth the operating results for PNM Electric.
Variance
$ 162,945
$ 152,413
$ 10,532
7,283
Intersegment energy transfer
2,633
616
28,563
26,100
2,463
Transmission and distribution O&M
8,340
7,981
359
Customer related expense
5,552
4,532
1,020
1,537
(491)
Total non-fuel O&M
43,501
40,150
3,351
Corporate allocation
17,913
15,358
2,555
4,708
Taxes other than income taxes
5,027
5,144
(117)
(3,759)
Total non-fuel operating expenses
91,715
84,977
6,738
$ 20,477
$ 26,599
$ (6,122)
94
The following table shows electric revenues by customer class and average customers:
PNM Electric Revenues
(In thousands, except customers)
Residential
$ 61,580
$ 55,615
$ 5,965
Commercial
73,090
70,594
2,496
Industrial
16,054
15,964
Transmission
6,287
4,490
1,797
5,934
5,750
184
$162,945
$152,413
$10,532
Average customers
419,195
408,225
10,970
The following table shows electric sales by customer class:
(Megawatt hours)
754,103
675,228
78,875
1,022,049
980,115
41,934
333,781
330,392
3,389
81,480
77,969
3,511
2,191,413
2,063,704
127,709
Operating revenues increased $10.5 million, or 6.9%, from the prior year quarter. Retail electricity sales increased 6.2%, to 2.19 million MWh in the third quarter of 2005 compared to 2.06 million MWh in the third quarter of 2004. Customer growth was 2.7% quarter over quarter and a 3.4% increase in weather normalized retail electric load growth resulted in a $5.5 million increase in revenues. Warmer weather in the third quarter of 2005 compared to 2004 contributed $4.3 million to the increase in revenues. Cycle-weighted Cooling Degree Days for Albuquerque, New Mexico increased approximately 20.2%, to 1,158 during the third quarter of 2005 compared to 963 during the third quarter of 2004. In addition, increased transmission revenues, primarily from point-to-point customers, increased revenues $1.8 million. These increases were offset slightly by a 2.5% electric rate reduction effective September 1, 2005 that decreased revenues $1.0 million.
The gross margin, or operating revenues minus cost of energy sold and intersegment energy transfer, increased $0.6 million, or 0.6%, over the prior year quarter due to the retail revenue growth discussed above offset by the higher related costs to serve the increased load, increased plant outage costs and higher purchase power contract prices.
95
Total non-fuel O&M expenses increased $3.4 million, or 8.3%, over the prior year quarter primarily due to increased energy production costs. Energy production costs increased $2.5 million, or 9.4% due primarily to plant outages during the third quarter of 2005 at SJGS, PVNGS and Four Corners that increased costs $0.9 million, $0.4 million and $0.2 million, respectively, and higher general plant maintenance and other costs of $0.6 million. Transmission and distribution O&M increased $0.4 million, or 4.5%, primarily due to higher fleet-related expenses during the third quarter of 2005 than during the third quarter of 2004. Customer related expense increased $1.0 million, or 22.5%, primarily due to increased consulting fees related to FERC proceedings. Administrative and general expenses decreased $0.5 million, or 31.9%, primarily due to lower benefit costs at SJGS, PVNGS and Four Corners of $0.7 million, partially offset by increased legal costs of $0.2 million for routine business matters.
Depreciation and amortization increased $4.7 million, or 37.5%, over the prior year quarter due to asset and software additions placed in service in December 2004 and the first nine months of 2005. The Company expects depreciation to continue to increase in the future as a result of increased investment in new information technology platforms.
PNMR acquired TNP on June 6, 2005, and results in this section are presented from the acquisition date forward only, comparable results from 2004 are not presented. For the three months ended September 30, 2005, the TNMP Electric segment increased PNMR revenues by $71.4 million.
The table below sets forth the operating results for TNMP Electric.
5,671
1,433
522
7,626
3,735
30,248
$15,429
96
TNMP Electric Revenues
$28,637
General Services
9,150
Primary/Economy/Transmission
10,809
Secondary
13,323
Municipal/Lighting
2,346
7,176
Average customers *
259,168
* Under TECA, customers of TNMP in Texas have the ability to choose First Choice or any other REP to provide energy; however, TNMP delivers energy to customers within TNMP's service area regardless of the REP chosen. Therefore TNMP earns revenue for that delivery and First Choice earns revenue on the usage of that energy by its customers. The average customers reported above include approximately 155,679 customers of TNMP who have chosen First Choice as their REP. These customers are also included below in the First Choice segment. For PNMR consolidated reporting purposes, these customers are included only once in the consolidated customer count.
953,947
69,010
537,464
578,609
39,238
2,178,268
* Under TECA, customers of TNMP in Texas have the ability to choose First Choice or any other REP to provide energy; however, TNMP delivers energy to customers within TNMP's service area regardless of the REP chosen. Therefore, TNMP earns revenue for that delivery and First Choice earns revenue on the usage of that energy by its customers. The megawatt hours reported above include approximately 856,839 megawatt hours used by customers of TNMP who have chosen First Choice as their REP. These megawatt hours are also included below in the First Choice segment.
97
The table below sets forth the operating results for PNM Gas.
$ 78,687
$ 73,530
$ 5,157
5,385
(228)
630
663
(33)
7,254
6,750
504
5,183
5,267
(84)
398
227
13,465
12,851
614
10,315
8,088
2,227
1,998
1,521
477
(1,855)
27,813
25,294
2,519
Operating income/(loss)
$ (2,638)
$ 109
$ (2,747)
The following table shows gas revenues by customer and average customers:
PNM Gas Revenues
$ 34,202
$ 29,170
$ 5,032
12,232
10,595
1,637
598
287
311
Transportation*
3,076
3,650
(574)
28,579
29,828
(1,249)
469,947
459,461
10,486
* Customer owned gas.
98
The following table shows gas throughput by customer class:
(Thousands of decatherms)
2,266
2,257
1,230
1,319
(89)
10,334
14,907
(4,573)
2,849
4,566
(1,717)
16,761
23,090
(6,329)
*Customer-owned gas.
Operating revenues increased $5.2 million, or 7.0%, over the prior year quarter. Residential and commercial revenues increased $5.0 million and $1.6 million, respectively, primarily due to average customer growth of 2.3%. These increases were partially offset by total gas sales volumes, which decreased 27.4% primarily due to decreased off-system transportation volume, which is included in the $0.6 million change in transportation revenues. In addition, other revenue decreased $1.2 million primarily due to a decrease in off-system gas sales.
The gross margin, or operating revenues minus cost of energy sold, decreased $0.2 million, or 0.9%, over the prior year quarter. This decrease was due mainly to the decrease in transportation volumes noted above.
Transmission and distribution O&M increased $0.5 million, or 7.5%, over the prior year quarter primarily due to increased outside services contracts for process improvement initiatives.
Depreciation and amortization increased $1.1 million, or 23.1%, over the prior year quarter primarily due to asset and software additions placed in service in December 2004 and the first nine months in 2005. The Company expects depreciation to continue to increase in the future as a result of increased investment in new information technology platforms.
The table below sets forth the operating results for PNM Wholesale.
$ 179,855
$ (4,384)
4,510
(2,633)
(6,261)
7,335
6,972
363
(9)
(91)
425
1,813
1,128
685
9,497
8,033
1,464
1,196
1,006
190
590
859
(3,609)
14,221
15,557
(1,336)
$ 2,405
$ 7,330
$ (4,925)
The following table shows revenues by customer class:
PNM Wholesale Revenues
Long-term contracts*
$ 39,866
$ 41,600
$ (1,734)
Short-term sales *
139,989
142,639
(2,650)
$179,855
$184,239
*Includes mark-to-market gains/(losses).
100
The following table shows sales by customer class:
PNM Wholesale Sales
Long-term contracts
651,178
783,582
(132,404)
Short-term sales
2,300,775
2,764,755
(463,980)
2,951,953
3,548,337
(596,384)
Operating revenues decreased $4.4 million, or 2.4%, from the prior year quarter. This decrease in wholesale electric sales primarily reflects lower sales volumes resulting from below normal levels of plant performance, combined with increasing retail load. PNM Wholesale sold 2.95 million MWh of electricity for the three months ended September 30, 2005 compared to 3.55 million MWh for the same period in 2004, a decrease of 16.8%. This decrease was partially offset by average wholesale sales prices, which increased 20.2% over the prior year period. Revenues from long-term contracts decreased $1.7 million, or 4.2%, from 2004 due primarily to the expiration of a customer contract, partially offset by customer load growth and higher index-based prices on existing contracts. Short-term sales decreased $2.7 million, or 1.9%, compared to the third quarter of 2004 due to decreased volumes caused by a reduction in plant availability and increased retail load, partially offset by an increase in sales prices.
The gross margin, or operating revenues minus cost of energy sold and intersegment energy transfer, decreased $6.3 million, or 27.4%, from the prior year quarter. Decreased plant availability reduced the availability of less expensive excess energy for sale in the wholesale market. In addition, higher purchase power contract prices further reduced the margin earned on fixed sales-price contracts. Long-term sales margin increased $0.6 million due to increased customer growth and higher index-based prices on existing contracts, partially offset by the expiration of a long-term contract. Short-term margin decreased $6.9 million primarily resulting from lower plant availability and increased purchase power prices. PNM Wholesale's mark-to-market position increased to a $1.2 million loss in 2005 from a $3.2 million loss in 2004.
Total non-fuel O&M increased $1.5 million, or 18.2%, from the prior year quarter. Energy production costs increased $0.4 million primarily due to higher plant maintenance costs in 2005 compared to 2004, resulting from the plant outages. Customer-related expense increased $0.4 million in the third quarter of 2005 primarily due to a third quarter 2004 reduction of incentive plan costs compared to no such reduction during the third quarter of 2005. Administration and general expense increased $0.7 million, primarily due to a customer billing settlement. Depreciation and amortization expenses increased $0.6 million due to the addition of new technology platforms that were placed in service in December 2004 and the first nine months in 2005. The Company expects depreciation to continue to increase in the future as a result of this increased investment in new technology platforms.
101
PNMR acquired TNP on June 6, 2005. Results in this section are presented from the acquisition date forward only, comparable results from 2004 are not presented. For the three months ended September 30, 2005, the First Choice segment increased PNMR revenues by $155.5 million.
The table below sets forth the operating results for First Choice.
1,672
4,647
6,319
3,659
1,822
20,106
$ 14,622
First Choice Electric Revenues
$102,013
Mass-market
25,208
Mid-market
21,980
6,278
215,376
* See note above in the TNMP Electric segment discussion about the impact of TECA.
846,683
205,183
236,604
13,565
1,302,035
Corporate Administrative and General Expenses
Corporate administrative and general expenses, which represent costs that are driven primarily by corporate-level activities, are allocated to the business segments and presented in the corporate allocation line item in the segment statements. These costs increased $12.4 million, or 49.6%, to $37.3 million for the third quarter of 2005, compared to $24.9 million for the third quarter of 2004. This increase is due to acquisition-related costs of $4.2 million, increased labor costs of $0.9 million resulting from the transfer of employees from operations to corporate, increased legal and environmental costs of $1.4 million, related in part to an environmental reserve and increased audit fees of $0.4 million.
PNMR Consolidated
Other Income and Deductions
Interest income increased $1.5 million, or 16.1%, due to short-term interest of $0.2 million related to cash received from PNMR's issuance of hybrid income term securities, interest of $1.3 million related to TNP's cash balance, which PNMR did not have in the prior year, and a $0.6 million increase related to higher PGAC balances caused by increasing gas prices. These increases were partially offset by lower interest income of $0.8 million due to pay-down of principal on the Palo Verde capital trust.
Other income increased $3.9 million due to a mark-to-market gain of $1.8 million from an interest rate swap, an increase of approximately $1.3 million in merchandising revenues, primarily from emergency assistance services (offset by the related expenses in other deductions below), and other miscellaneous income of $0.6 million.
Carrying charges on regulatory assets were $1.9 million in the three months ended September 30, 2005. This represents interest income on TNMP regulatory assets.
Other deductions increased $7.3 million due to a $3.6 million loss on the Wood River investment (see Note 4 - "Fair Value of Financial Instruments," in the Notes to Consolidated Financial Statements), $1.0 million in increased expenses related in merchandising revenues (offset by the related revenues in other income above) and miscellaneous tax-related adjustments of $1.6 million.
Interest charges increased $15.9 million due to interest of $3.2 million related to the hybrid income term securities issued March 30, 2005, $4.3 million of expenses related to increased commercial paper borrowings and $7.3 million related to debt from the TNP operations, which PNMR did not have in the prior year.
Income Taxes
PNMR's consolidated income tax expense was $15.9 million for the three months ended September 30, 2005, compared to $14.7 million for the three months ended September 30, 2004. The increase was due to the impact of higher pre-tax earnings. PNMR's effective income tax rates for the three months ended September 30, 2005 and 2004 were 35.45% and 34.78%, respectively.
Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004
PNMR's net earnings for the nine months ended September 30, 2005 were $60.5 million or $0.92 per diluted share of common stock compared to $69.0 million or $1.13 per diluted share of common stock in the nine months ended September 30, 2004. The decrease in earnings and earnings per share was driven primarily by acquisition related costs and other non-recurring charges of $14.5 million, net of income taxes, which consisted of acquisition integration costs of $5.4 million, TNP debt refinancing costs of $5.0 million, software write-offs of $2.7 million and the recognition of a regulatory liability of $1.4 million associated with the NMPRC's approval of the TNP acquisition. In addition, the Company experienced below normal levels of plant performance, which reduced the amount of electricity the Company sold on the wholesale market and forced the Company to purchase power to meet jurisdictional and contractual wholesale needs. In addition, the margin on fixed-price contracts decreased, as increases in purchased power contract prices that were driven by increasing fuel prices were not able to be passed on to customers with fixed sales prices. These decreases to net earnings were partially offset by the addition of the TNP operations for June 6 through September 30, 2005 and an increase in cost of service gas rates.
The following discussion is based on the methodology that management uses for making operating decisions and assessing performance of its various business activities. See Note 3 - "Segment Information," in the Notes to Consolidated Financial Statements for additional information regarding these results and the consolidated financial statements.
104
In addition, adjustments related to EITF Issue 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not Held for Trading Purposes," are excluded. This accounting pronouncement requires a net presentation of realized gains and losses for certain non-trading derivatives. Management evaluates wholesale operations on a gross presentation basis due to its primarily net-asset-backed marketing strategy and the importance it places on the Company's ability to repurchase and remarket previously sold capacity.
105
$ 435,908
$ 421,977
$ 13,931
8,812
9,435
(4,316)
88,844
85,191
3,653
22,965
23,205
14,252
13,187
1,065
5,787
4,151
1,636
131,848
125,734
6,114
48,124
50,556
(2,432)
6,393
15,045
15,601
(556)
(5,218)
262,214
257,913
4,301
$ 48,075
$ 56,692
$ (8,617)
$ 165,638
$ 156,568
$ 9,070
192,979
190,459
2,520
46,597
46,224
373
15,325
13,324
2,001
15,369
15,402
416,417
405,598
10,819
106
PNM Electric Sales
2,014,615
1,898,537
116,078
2,661,667
2,619,447
42,220
967,269
959,700
7,569
195,496
193,696
1,800
5,839,047
5,671,380
167,667
Operating revenues increased $13.9 million, or 3.3%, over the prior year. Retail electricity sales increased 3.0%, to 5.84 million MWh in the first nine months of 2005 compared to 5.67 million MWh in the first nine months of 2004. Customer growth was 2.7% year over year and weather-normalized retail electric load growth was 2.6% in 2005. Average customer load growth, when normalized for the impact of weather and the leap year in 2004, increased revenues by $11.2 million. Cycle-weighted Cooling Degree Days for Albuquerque increased approximately 17.6% to 1,417 during the nine months ended September 30, 2005 compared to 1,205 during the nine months ended September 30, 2004, resulting in an increase in revenues of $3.2 million. These revenue increases were partially offset by a decrease of $1.3 million attributable to the 2004 leap year, with 2005 including one less day of revenues, and by a decrease of $1.0 million due to the 2.5% electric rate reduction effective September 1, 2005.
The gross margin, or operating revenues minus cost of energy sold and intersegment energy transfer, decreased $4.3 million, or 1.4%, from the prior year due to a reduction in power plant availability due to plant outages and a related increase in purchased power requirements to serve load. In addition, an increase in purchased power contract prices on pre-existing contracts reduced the margin earned on fixed-price sales. These decreases were partially offset by the increased revenues associated with retail load growth.
Total non-fuel O&M expenses increased $6.1 million, or 4.9%, over the prior year. Energy production costs increased $3.7 million, or 4.3%, due to higher plant maintenance costs in the nine months ended September 30, 2005 compared to the same period in 2004. Plant outage costs at SJGS, Reeves and PVNGS increased costs $2.2 million, $1.7 million and $0.4 million, respectively, for the nine months ended September 30, 2005. In addition, there were higher general plant maintenance and other costs of $0.4 million compared to the nine months ended September 30, 2004. These increases were partially offset by reduced outage costs at Four Corners of $1.0 million. On March 26, 2005, a circulating water pipe ruptured and forced SJGS Unit Four to be taken offline. This unexpected three-week outage was combined with a planned minor overhaul of the same unit as the Company then accelerated the planned outage to minimize the economic impact of the shutdown. SJGS Unit Four was back online on April 17, 2005. Energy production costs increased due to this outage, however the Company expects to have lower operating costs and recover a portion of the lost revenue in the fourth quarter of 2005 when the SJGS Unit Four planned outage would otherwise have occurred.
107
Customer related expense increased $1.1 million, or 8.1%, primarily due to increased consulting fees related to FERC proceedings. Administrative and general expenses increased $1.6 million, or 39.4%, over the prior year primarily due to increased labor costs of $0.8 million and increased legal costs of $0.5 million for routine business matters.
Depreciation and amortization increased $6.4 million, or 13.9%, over the prior year due to asset and software additions placed in service in December 2004 and the first nine months of 2005. The Company expects depreciation to continue to increase in the future as a result of increased investment in new information technology platforms.
PNMR acquired TNP on June 6, 2005, and results in this section are presented from the acquisition date forward only. For the nine months ended September 30, 2005, which includes results from June 6 through September 30, 2005, the TNMP Electric segment increased PNMR revenues by $90.7 million.
For the Period
June 6 - September 30, 2005
6,821
1,735
810
9,366
5,196
38,637
$19,573
108
$37,301
11,407
13,404
16,637
2,962
8,965
258,939
* Under TECA, customers of TNMP in Texas have the ability to choose First Choice or any other REP to provide energy; however, TNMP delivers energy to customers within TNMP's service area regardless of the REP chosen. Therefore TNMP earns revenue for that delivery and First Choice earns revenue on the usage of that energy by its customers. The average customers reported above include approximately 156,213 customers of TNMP who have chosen First Choice as their REP. These customers are also included below in the First Choice segment. For PNMR consolidated reporting purposes, these customers are included only once in the consolidated customer count.
1,251,919
86,350
682,922
726,807
48,688
2,796,686
* Under TECA, customers of TNMP in Texas have the ability to choose First Choice or any other REP to provide energy; however, TNMP delivers energy to customers within TNMP's service area regardless of the REP chosen. Therefore, TNMP earns revenue for that delivery and First Choice earns revenue on the usage of that energy by its customers. The megawatt hours reported above include approximately 1,086,528 megawatt hours used by customers of TNMP who have chosen First Choice as their REP. These megawatt hours are also included below in the First Choice segment.
$ 326,357
$ 330,290
$ (3,933)
(7,686)
3,753
1,827
1,676
151
20,621
21,142
(521)
14,496
14,132
364
2,936
2,128
808
39,880
39,078
802
28,198
27,554
644
2,761
6,004
5,546
458
(534)
93,084
88,953
4,131
$ 12,034
$ 12,412
$ (378)
110
$ 185,821
$ 183,961
$ 1,860
57,581
59,547
(1,966)
1,523
1,577
10,193
11,593
(1,400)
71,239
73,612
(2,373)
470,026
459,996
10,030
PNM Gas Throughput
18,970
19,605
(635)
7,115
7,592
(477)
233
27,586
35,641
(8,055)
8,834
11,701
(2,867)
62,717
74,772
(12,055)
*Customer-owned gas
Operating revenues decreased $3.9 million, or 1.2%, over the prior year. Warmer weather in 2005 compared to 2004 caused a $4.7 million decrease in revenues. Cycle-weighted Heating Degree Days for Albuquerque decreased approximately 2.7% in 2005 compared to 2004. In addition, total gas sales volumes decreased 16.1% primarily due to decreased off-system transportation of $1.4 million. In addition, other revenue decreased $2.4 million primarily due to a decrease in off-system gas sales and lower irrigation customer usage. These decreases were partially offset by average customer growth of 2.2%, which increased gas revenues $2.4 million, and an increase of $6.7 million due to a residential cost of service rate increase beginning in April 2004.
The gross margin, or operating revenues minus cost of energy sold, increased $3.8 million, or 3.7%, over the prior year. This increase was due mainly to customer growth and the NMPRC-approved residential rate increase, partially offset by the impact of warmer weather in 2005 compared to 2004 described above.
111
Total non-fuel O&M expenses were largely unchanged over the prior year. Transmission and distribution O&M expense decreased $0.5 million, or 2.5%, primarily due to a transfer of employees from administrative and general. Due primarily to this transfer that increased labor costs, administrative and general expenses increased by $0.8 million. Customer related expenses increased $0.4 million, or 2.6%, due primarily to increased advertising and billing system expenses.
Depreciation and amortization increased $2.8 million, or 19.7%, over the prior year primarily due to asset and software additions placed in service in December 2004 and the first nine months of 2005. The Company expects depreciation to continue to increase in the future as a result of increased investment in new information technology platforms.
$454,141
$475,414
$ (21,273)
(1,898)
(9,435)
(9,940)
21,737
21,110
627
(14)
716
(81)
5,106
27,685
27,063
622
3,249
3,315
(66)
1,110
2,615
2,658
(5,289)
48,092
51,758
(3,666)
$ 16,320
$ 22,594
$ (6,274)
112
$ 115,238
$ 118,484
$ (3,246)
338,903
356,930
(18,027)
$ 454,141
$(21,273)
1,940,063
2,216,392
(276,329)
6,375,214
7,561,919
(1,186,705)
8,315,277
9,778,311
(1,463,034)
Operating revenues decreased $21.3 million, or 4.5%, from the prior year. This decrease in wholesale electric sales primarily reflects lower sales volumes resulting from below normal levels of plant performance. PNM Wholesale sold 8.32 million MWh of electricity for the nine months ended September 30, 2005 compared to 9.78 million MWh for the same period in 2004, a decrease of 15.0%. This decrease was partially offset by average wholesale sales prices, which increased 14.4% over the prior year period. Revenues from long-term contracts decreased $3.2 million, or 2.7%, from 2004 due primarily to the expiration of a customer contract, partially offset by customer load growth, higher index-based prices on existing contracts and higher prices associated with SO2 credit sales. Short-term sales decreased $18.0 million primarily due to decreased volumes caused by a reduction in plant availability, partially offset by higher sales prices.
The gross margin, or operating revenues minus cost of energy sold and intersegment energy transfer, decreased $9.9 million, or 13.4%, from the prior year. Decreased plant availability and increased retail load decreased the availability of less expensive excess energy for sale in the wholesale market. In addition, higher purchased power contracts prices decreased the margin on fixed-price sales contracts. Long-term sales margin was relatively unchanged from the prior year due to the impacts of customer load growth and higher prices associated with SO2 credit sales that were offset by a decrease in sales volume due to the expiration of a long-term contract and increased purchased power contract prices that could not be passed through to customers based on fixed-price sales contracts. Short-term margin decreased $10.0 million primarily resulting from lower plant availability and increased retail
loads, which caused a decrease in energy available to sell on the wholesale market. PNM Wholesale's mark-to-market position fell to a $0.4 loss in 2005 from a $1.3 million gain in 2004.
Total non-fuel O&M increased $0.6 million, or 2.3%, from the prior year, due to increased energy production costs, primarily due to higher plant maintenance costs in 2005 compared to 2004, resulting from plant outages.
Depreciation and amortization increased $1.1 million, or 10.5%, over the prior year due to the addition of new technology platforms that were placed in service in December 2004 and the first nine months of 2005. The Company expects depreciation to continue to increase in the future as a result of this increased investment in new technology platforms.
PNMR acquired TNP on June 6, 2005, and results in this section are presented from the acquisition date forward only. For the nine months ended September 30, 2005, which includes results from June 6 through September 30, 2005, the First Choice segment increased PNMR revenues by $198.5 million.
2,138
5,736
7,874
4,789
2,334
25,428
$ 18,248
114
$131,278
31,823
27,844
7,565
215,524
1,093,015
260,607
304,024
16,514
1,674,160
Corporate administrative and general expenses, which represent costs that are driven primarily by corporate-level activities, are allocated to the business segments and presented in the corporate allocation line item in the segment statements. These costs increased $18.8 million, or 23.2%, over the prior year to $99.5 million. This increase is due to acquisition related costs of $9.2 million, increased labor costs of $3.1 million resulting from the transfer of employees from operations to corporate, increased legal and environmental costs of $1.2 million related to PUHCA filings, financing costs for PNMR's hybrid income term securities, an environmental reserve and tax matters, $0.9 million in increased audit fees and $0.3 million in general expenses for TNMP and First Choice operations. These increases were partially offset by lower pension and benefit costs of $1.7 million resulting from higher returns on pension investments.
115
Interest income increased $3.6 million, or 13.0%, due to short-term interest of $1.9 million related to cash received from PNMR's issuance of hybrid income term securities, interest of $1.5 million related to TNP's cash balance, which PNMR did not have in the prior year, $0.6 million related to higher PGAC balances caused by increasing gas prices and $0.5 million from interest on amended federal income tax returns. These increases were partially offset by lower interest income of $1.5 million due to pay-down of principal on the Palo Verde capital trust.
Other income increased $6.9 million due to increased gains of $1.6 million from investments in PNMR's cash management program, a mark-to-market gain of $1.8 million from an interest rate swap, a $1.9 million increase in earnings in excess of the required amount in the PNM decommissioning trust and approximately $1.9 million in merchandising revenues, primarily from emergency assistance services (offset by the related expenses in other deductions below).
Carrying charges on regulatory assets were $2.4 million from June 6 through September 30, 2005. This represents interest income on TNMP regulatory assets from the date of acquisition.
Other deductions increased $13.3 million due to a $4.5 million write-off of software costs, a $3.6 million loss on the Wood River investment (see Note 4 - "Fair Value of Financial Instruments," in the Notes to Consolidated Financial Statements), $1.5 million increased expenses related to merchandising revenues (offset by the related revenues in other income above) and miscellaneous tax-related adjustments of $1.6 million.
Interest charges increased $24.5 million, or 64.3%, due to interest and refinancing costs of $6.4 million related to the hybrid income term securities issued March 30, 2005, $4.3 million of expenses related to increased commercial paper borrowings, short-term interest costs of $1.2 million for operations and $11.3 million related to debt from the TNP operations, which PNMR did not have in the prior year.
PNMR's consolidated income tax expense was $34.5 million for the nine months ended September 30, 2005, compared to $38.7 million for the nine months ended September 30, 2004. The decrease was due to the impact of lower pre-tax earnings. PNMR's effective income tax rates for the nine months ended September 30, 2005 and 2004 were 35.30% and 35.78%, respectively.
116
PNM's segments are PNM Electric, PNM Gas and PNM Wholesale and are identical to the segments presented above in "Results of Operations" for PNMR. Income taxes and non-operating items are discussed on a consolidated basis for PNM and are in conformity with the presentation in PNM's consolidated financial statements.
PNM Consolidated
Other income increased $1.9 million, or 95.4%, due to an increase of approximately $1.3 million in merchandising revenues, primarily from emergency assistance services and other miscellaneous income of $0.6 million. Other deductions increased $1.5 million due to an increase of $1.0 million in corresponding merchandising costs, primarily from emergency assistance services and other miscellaneous expenses of $0.5 million.
PNM's consolidated income tax expense was $6.4 million for the three months ended September 30, 2005, compared to $14.8 million for the three months ended September 30, 2004. The decrease was due to the impact of lower pre-tax earnings. PNM's effective income tax rates for the three months ended September 30, 2005 and 2004 were 36.30% and 34.81%, respectively. The increase in the effective tax rate was due to a decrease in permanent tax benefits.
As noted previously in the third quarter presentation, PNM's segments are PNM Electric, PNM Gas and PNM Wholesale and are identical to the segments presented above in "Results of Operations" for PNMR. Income taxes and non-operating items are discussed on a consolidated basis for PNM and are in conformity with the presentation in PNM's consolidated financial statements.
117
Other income increased $3.9 million, or 74.1%, due to an increase of approximately $1.9 million in merchandising revenues, primarily from emergency assistance services and a $1.9 million increase in earnings in excess of the required amount in the PNM decommissioning trust. Other deductions increased $6.9 million due to an increase of $1.5 million in corresponding merchandising costs, primarily from emergency assistance services and the write-off of software costs of $4.5 million.
PNM's consolidated income tax expense was $27.4 million for the nine months ended September 30, 2005, compared to $39.8 million for the nine months ended September 30, 2004. The decrease was due to the impact of lower pre-tax earnings. PNM's effective income tax rates for the nine months ended September 30, 2005 and 2004 were 36.44% and 35.87%, respectively.
TNMP operates in only one reportable segment, "TNMP Electric." See Note 3 - "Segment Information," in the Notes to Consolidated Financial Statements for additional information regarding these results and the consolidated financial statements. Results for the three months ended September 30, 2005 include the effects of purchase accounting, which are not included in the three months ended September 30, 2004.
The table below sets forth the operating results for TNMP.
External customers
$49,373
$44,760
$ 4,613
29,972
(7,904)
(3,291)
(192)
48,776
(3,099)
1,228
1,250
183
4,537
6,302
(1,765)
11,640
11,994
(354)
381
(1,348)
30,463
31,696
(1,233)
(1,866)
Other Income and deductions:
982
862
365
497
(614)
979
279
$ (1,166)
119
(In thousands except customers)
$28,373
$ 264
8,357
793
13,699
(2,890)
14,729
(1,406)
Municipal Lighting
2,572
(226)
7,002
174
$(3,291)
254,504
4,664
TNMP Electric Sales
891,676
62,271
65,469
3,541
545,594
(8,130)
534,053
44,556
37,760
1,478
2,074,552
103,716
Operating revenues decreased $3.3 million, or 4.4%, from the prior year quarter. Gross margin for the three months ended September 30, 2005 decreased $3.1 million, or 6.4%, compared with the third quarter of 2004. The decrease was primarily due to a $6.8 million decrease in revenues due to a rate reduction effective May 1, 2005 that was part of the PUCT's approval of the TNP acquisition, a $0.6 million margin decrease due to the reduced operations of a major customer and a $3.0 million increase in costs of energy resulting from higher purchased power costs due to increasing gas prices. Partially offsetting these decreases were increases in revenues resulting from warm weather of $3.6 million, $3.0 million related to higher fuel-recovery, $0.7 million due to customer growth, and lower purchased power costs due to the overall decrease in volumes.
Total non-fuel operating expenses decreased $1.2 million, or 3.9%, due primarily to a decrease in non-fuel O&M of $0.4 million and a decrease of $1.3 million in income tax expense, offset by an increase of $0.4 million in depreciation and amortization expense. Administrative and general expenses decreased $1.8 million primarily due to decreased legal, environmental and regulatory expenses of $2.7 million, partially offset by increases related to synergy credits to
120
customers and general corporate expenses of $1.1 million. Transmission and distribution O&M increased $1.2 million primarily due to $0.5 million in increased expenses for the preparation and restoration efforts related to hurricane Rita and $0.5 million related to the maintenance of overhead lines in 2005. Depreciation expenses increased as a result of additions to fixed assets.
Net other income and deductions increased $1.0 million due to increased interest income calculated on stranded costs as authorized by the PUCT.
TNMP operates in only one reportable segment, "TNMP Electric." See Note 3 - "Segment Information," in the Notes to Consolidated Financial Statements for additional information regarding these results and the consolidated financial statements. Results for the nine months ended September 30, 2005 include the effects of purchase accounting, which are not included in the nine months ended September 30, 2004.
121
$171,071
$201,454
$(30,383)
32,425
203,496
2,042
76,351
2,750
127,145
127,853
(708)
Operating expenses:
15,931
1,560
3,835
3,740
15,366
18,375
(3,009)
35,132
36,486
(1,354)
22,853
667
17,710
10,592
138
86,287
86,826
(539)
40,858
(169)
Other income and deduction:
1,028
2,233
1,360
(133)
133
(1,210)
(419)
1,918
687
21,326
221
Net earnings before extraordinary
item
21,450
297
Extraordinary item:
Disallowance of stranded cost,
net of tax
$ 21,450
$98,133
122
$ 72,136
$ 70,929
$1,207
24,390
23,048
1,342
36,883
36,370
513
40,482
41,590
(1,108)
7,237
7,529
(292)
22,368
21,988
$203,496
$2,042
257,601
253,464
4,137
2,196,448
2,080,718
115,730
184,488
179,183
5,305
1,701,713
1,583,082
118,631
1,477,384
1,431,244
46,140
112,797
108,199
4,598
5,672,830
5,382,426
290,404
Operating revenues increased $2.0 million, or 1.0%, from the prior year. Gross margin for the nine months ended September 30, 2005 decreased by $0.7 million, or 0.6%, compared with the corresponding 2004 period. The overall decrease was primarily due to a $7.6 million decrease in revenues due to a rate reduction effective May 1, 2005 that was part of the PUCT's approval of the TNP acquisition, a $0.9 million decrease in margin due to the reduced operations of a major customer and a $2.9 million increase in costs of energy resulting from higher purchased power costs due to increasing gas prices. These decreases were offset by a $4.8 million increase in revenues due to higher sales resulting from warm weather, a $1.8 million increase in revenues due to customer growth and $3.6 million related to higher fuel-recovery.
Total non-fuel operating expenses decreased $0.5 million, or 0.6%, due primarily to a decrease in non-fuel O&M of $1.4 million offset by an increase of $0.7 million in depreciation and amortization expense. Administrative and general expenses decreased $3.0 million, primarily due to decreased legal, environmental and regulatory expenses of $4.7 million, partially offset by increases related to synergy credits to customers and general corporate expenses of $1.3 million. Transmission and distribution O&M increased $1.6 million primarily
123
due to $0.6 million in increased expenses for the preparation and restoration efforts related to hurricane Rita and $0.5 million related to the maintenance of overhead lines in 2005. Depreciation expense increased as a result of additions to fixed assets.
Net other income and deductions increased by $0.7 million due primarily to a $1.0 million increase in interest revenues resulting from higher cash balances and higher interest rates in 2005.
CRITICAL ACCOUNTING POLICIES
The Company employs certain critical accounting policies that require use of judgments and assumptions that are subject to uncertainty. The amounts reported in the consolidated interim financial statements that are related to those critical accounting policies could be different if either different judgments were made or different assumptions were used. Those critical accounting policies are discussed below.
Purchase Accounting. The acquisition of TNP was accounted for using the purchase method of accounting as prescribed in SFAS 141; accordingly, purchase accounting adjustments have been reflected in the financial statements of TNP for all periods subsequent to June 6, 2005. The business operations of TNP were not significantly changed as a result of the acquisition, and post-acquisition and pre-acquisition operating results, except as noted in the discussion, are comparable.
Goodwill and Intangible Assets. In accordance with SFAS 141, the Company has revalued the assets and liabilities acquired at their respective fair values. In accordance with SEC regulations, the difference between the purchase price and the fair value of the assets acquired and liabilities assumed is recorded by the acquired businesses. Goodwill and other intangible assets and liabilities were also recorded by the acquired businesses and are either amortized or are measured for impairment annually, on December 31, in accordance with SFAS 142.
As of September 30, 2005, there have been no other significant changes with regard to the critical accounting policies disclosed in PNMR's, PNM's and TNMP's Annual Reports on Forms 10-K for the year ended December 31, 2004. The policies disclosed included the accounting for revenue recognition, regulatory assets and liabilities, asset impairment, pension plan, self-insurance, contingent liabilities and environmental issues.
LIQUIDITY AND CAPITAL RESOURCES
At September 30, 2005, PNMR had cash and short-term investments of $144.8 million compared to $17.2 million in cash and short-term investments at December 31, 2004.
Cash provided by operating activities for the nine months ended September 30, 2005 was $170.6 million compared to $212.6 million for the nine months ended September 30, 2004. PNMR's net earnings for the nine months ended September 30, 2005 were $60.5 million, a 12.3% decrease in net earnings compared to $69.0 million in the nine months ended September 30, 2004, which contributed to the decrease in cash provided by operating activities. The decrease in earnings was driven primarily by acquisition related costs and other non-recurring charges.
124
In addition, the Company experienced below normal levels of plant performance, which reduced the amount of electricity the Company sold on the wholesale market and forced the Company to purchase power to meet jurisdictional and contractual wholesale needs. In addition, the margin on fixed-price contracts decreased, as increases in purchased power contract prices that were driven by increasing fuel prices were not able to be passed on to customers with fixed sales prices. These decreases to net earnings were partially offset by the addition of the TNP operations for June 6 through September 30, 2005 and an increase in cost of service gas rates. The decrease was offset in part by increases in cash flows from greater efficiency in management of accounts receivables, including the PGAC.
Cash used for investing activities was $84.4 million for the nine months ended September 30, 2005 compared to $79.9 million for the nine months ended September 30, 2004. Cash flows used for investing activities were higher in the current period due primarily to the cash balances acquired from TNP, net of the cash paid to acquire TNP. The increase in cash flows used for investing activities was offset by increased cash payments for utility plant additions.
Cash generated by financing activities was $41.4 million for the nine months ended September 30, 2005 compared to cash used for financing activities of $136.9 million for the nine months ended September 30, 2004. Cash generated from financing activities in 2005 increased due to the issuance of short-term debt for $380.0 million to fund a portion of the cost of redemption of TNP preferred stock and senior notes, the issuance of the equity units for $239.8 million and the issuance of common stock for $101.2 million. The increase in cash generated by financing activities was partially offset by the redemption of TNP preferred stock of $224.6 million and the repayment of long-term debt of $399.6 million, including the repayment of $296.5 million in TNP senior notes and the repayment of $110.5 million under the TNP credit agreement. Financing activities in 2004 consisted primarily of short-term debt repayments.
Cash provided by operating activities for the nine months ended September 30, 2005 was $95.0 million compared to $217.1 million for the nine months ended September 30, 2004. This decrease in cash flows was due primarily to lower year to date earnings in 2005 and reduced levels of accounts payable and increased levels of accounts receivable in 2005 as a result of higher winter season gas usage in December 2004.
Cash used for investing activities was $71.1 million for the nine months ended September 30, 2005 compared to $86.0 million for the nine months ended September 30, 2004. The decrease in cash used for investing activities was due primarily to a $12.2 million purchase of bond investments in 2004 that did not recur in 2005.
Cash used by financing activities was $27.5 million for the nine months ended September 30, 2005 compared to cash used for financing activities of $134.7 million for the nine months ended September 30, 2004. The decrease in cash used for financing activities was due primarily to cash received from short-term borrowings in 2005 of $53.6 million compared to the use of cash in 2004 of $97.7 million to repay short-term borrowings. For the nine months ended September 30, 2005, $53.6 million of cash was provided from financing activities as a result of the issuance of commercial paper primarily to fund costs related to the TNP acquisition. For the nine months ended September 30, 2004, less cash was provided from financing activities due to a decrease in securitized accounts receivable balances of $54.9 million, the repayment of a
revolving line of credit balance of $20.0 million and the repayment of commercial paper outstanding of $22.8 million. The decrease in cash flows from financing activities was offset in part by the payment of $80.0 million in dividends to PNMR.
TNMP's cash provided by operating activities for the nine months ended September 30, 2005 was $61.3 million compared to $50.7 million for the nine months ended September 30, 2004. TNMP's cash flow from operations was $10.6 million higher in the current period than in the nine months ended September 30, 2004, due primarily to lower payments for accounts payable.
Cash used for investing activities was $35.0 million for the nine months ended September 30, 2005 compared to $33.4 million for the nine months ended September 30, 2004. Utility plant additions decreased as a result of lower capital spending in anticipation of the acquisition of TNP by PNMR.
Cash used for financing activities for the nine months ended September 30, 2005 was $62.0 million compared to cash used for financing activities for the nine months ended September 30, 2004 of $15.3 million. In the third quarter of 2005, TNMP, a wholly owned subsidiary of TNP, had a cash outlay of $62.0 million to redeem a portion of the TNMP stock held by TNP. TNMP activities in 2004 consisted primarily of short-term debt repayments and dividends paid.
Capital Requirements
Total capital requirements include construction expenditures as well as other major capital requirements and cash dividend requirements for both common and preferred stock. The main focus of the Company's current construction program is upgrading generation resources, upgrading and expanding the electric and gas transmission and distribution systems and purchasing nuclear fuel. Projections for total capital requirements for 2005, including TNMP and First Choice, are $292.1 million with projections for construction expenditures for 2005 constituting $265.1 million of that total. Total capital requirements, including TNMP and First Choice, are projected to be $1,353 million and construction expenditures are projected to be $1,183 million for 2005-2009. These estimates are under continuing review and subject to on-going adjustment. This projection includes $49.0 million for the acquisition and construction of Luna, $49.0 million for PNM's estimated share of capital costs for new pollution control technology at SJGS (which is currently under review and may ultimately be higher) and $124.3 million for expansion at Afton. In July 2005, PNM filed with the NMPRC an application for a CCN in which PNM requested NMPRC approval to include in PNM's retail rate base in its next retail electric rate case the costs associated with the conversion of the Afton generating station from a combustion turbine to a combined cycle unit utilizing one of PNM's turbines in storage. The conversion to a combined-cycle unit, as proposed, would utilize a turbine currently in storage with a book value of $24.3 million. As part of the negotiations regarding regulatory treatment of the Afton facility, the parties also are discussing alternative equipment configurations under which the turbine in storage would not be used. If such an alternative configuration were to be agreed upon, the Company would evaluate other alternatives, including selling the unit, which could result in a write-down depending on prevailing market conditions for this type of equipment. The Company is unable to predict the outcome of the Afton CCN case.
126
The Company continues to look for appropriately priced generation acquisition and expansion opportunities to support retail electric load growth, for the continued expansion of its long-term contract business, and to supplement its natural transmission position in the Southwest and West.
During the nine months ended September 30, 2005, the Company utilized cash generated from operations and cash on hand, as well as its liquidity arrangements, to cover its capital requirements and construction expenditures. The Company anticipates that internal cash generation and current debt capacity will be sufficient to meet all of its capital requirements and construction expenditures for the years 2005 through 2009. To cover the difference in the amounts and timing of cash generation and cash requirements, the Company intends to use short-term borrowings under its current and future liquidity arrangements.
The main focus of PNM's current construction program is upgrading generation resources, upgrading and expanding the electric and gas transmission and distribution systems and purchasing nuclear fuel. Projections for total capital requirements for 2005 are $215.5 million with projections for construction expenditures for 2005 constituting $188.5 million of that total. Total capital requirements are projected to be $1,064 million and construction expenditures are projected to be $894.3 million for the years 2005 through 2009. These estimates are under continuing review and subject to on-going adjustment.
The Company's one-third interest in the 570 megawatt Luna facility, currently under construction, has been held in a wholly-owned subsidiary, PNMR Development and Management Corporation. Company management has recently made the decision to transfer the one-third interest to PNM, which PNM will continue to develop and which PNM will use as merchant plant. The Company expects the transfer to be completed by the end of November 2005.
The main focus of TNMP's current construction program is upgrading and expanding the electric transmission and distribution systems. Projections for total capital requirements for 2005 are $35.2 million. Total capital requirements are projected to be $227.2 million for the years 2005 through 2009. These estimates are under continuing review and subject to on-going adjustment.
127
Liquidity
As of October 28, 2005, PNMR had $615.0 million of liquidity arrangements. The liquidity arrangements consist of $600.0 million from an unsecured revolving credit facility, referred to as the PNMR Facility for purposes of this discussion, and $15.0 million in local lines of credit. As of October 28, 2005, there were no amounts borrowed under the PNMR Facility or the local lines of credit.
At October 28, 2005, First Choice had up to $300.0 million of borrowing capacity under the PNMR Facility. Any borrowings made by First Choice under this sublimit are guaranteed by PNMR. At October 28, 2005, First Choice had no borrowings outstanding under the PNMR Facility; however, First Choice had $5.7 million of letters of credit outstanding, which reduces the available capacity under the PNMR Facility. TNMP is also a borrower under the PNMR Facility, see "TNMP" detail below.
PNMR has established a commercial paper program under which it may issue up to $400.0 million in commercial paper for up to 270 days. The commercial paper is unsecured and the proceeds are used for short-term cash management needs. The PNMR Facility serves as a backstop for the outstanding commercial paper. As of October 28, 2005, there were $265.7 million of borrowings outstanding under this program.
PNMR's ability, if required, to access the capital markets at a reasonable cost and to provide for other capital needs is largely dependent upon its ability to earn a fair return on equity, its results of operations, its credit ratings, obtaining required regulatory approvals and financial and wholesale market conditions. Financing flexibility is enhanced by providing a high percentage of total capital requirements from internal sources and having the ability, if necessary, to issue long-term securities and to obtain short-term credit.
PNMR's credit outlook was considered stable by S&P and Moody's as of the date of this report. The Company is committed to maintaining or improving its investment grade ratings. In March 2005, S&P and Moody's rated PNMR's senior unsecured notes issued as part of its equity unit sales (see "Financing Activities" below) BBB- and Baa3, respectively. The PNMR commercial paper program discussed above has been rated A2 by S&P and P3 by Moody's.
Investors are cautioned that a security rating is not a recommendation to buy, sell or hold securities, that it is subject to revision or withdrawal at any time by the assigning rating organization, and that each rating should be evaluated independently of any other rating.
In Texas, capacity auctions are a semi-regular event mandated by the TECA to promote liquidity in the marketplace. Under these monthly or annual auctions, formerly integrated utilities are required to auction a portion of their capacity. The process is a simultaneous, multiple round bidding auction conducted over the internet. The most recent annual auction
began in August 2005, but was postponed for one week in September due to a hurricane. First Choice was required to post collateral for 100% of its planned bid of $120.0 million. PNMR initially posted $18.2 million in parental guarantees and $101.8 million in letters of credit in support of First Choice. First Choice won four 25 MW baseload blocks of capacity in October 2005 and two 25 MW cyclic blocks of capacity in September 2005. Upon completion of the auction, collateral requirements for the baseload capacity decreased to 25.9% of the outstanding commitment. First Choice resold the baseload capacity almost immediately and kept the capacity products for load management purposes.
As of October 28, 2005, PNM had $493.5 million of liquidity arrangements. The liquidity arrangements consist of $400.0 million from an unsecured revolving credit facility, referred to as the PNM Facility for purposes of this discussion, $70.0 million from an AR Securitization program and $23.5 million in local lines of credit. As of October 28, 2005, there were no amounts borrowed against the PNM Facility, the AR Securitization, or the local lines of credit; however, $4.5 million of letters of credit were outstanding, which reduces the available capacity under the PNM Facility.
At October 28, 2005, PNM also had a $20.0 million borrowing arrangement with PNMR, which is not included in the $493.5 million of liquidity arrangements discussed above. As of October 28, 2005 there were no amounts outstanding under this arrangement.
PNM has a commercial paper program under which PNM may issue up to $300.0 million in commercial paper for up to 365 days. The commercial paper is unsecured and the proceeds are used for short-term cash management needs. The PNM Facility serves as a backstop for PNM's outstanding commercial paper. As of October 28, 2005, PNM had $94.1 million in commercial paper outstanding under this program.
PNM's ability, if required, to access the capital markets at a reasonable cost and to provide for other capital needs is largely dependent upon its ability to earn a fair return on equity, its results of operations, its credit ratings, obtaining required regulatory approvals and financial and wholesale market conditions. Financing flexibility is enhanced by providing a high percentage of total capital requirements from internal sources and having the ability, if necessary, to issue long-term securities and to obtain short-term credit.
PNM's credit outlook was considered stable by S&P and Moody's as of the date of this report. The Company is committed to maintaining or improving its investment grade ratings. As of September 30, 2005, S&P rated PNM's business position as six, its senior unsecured notes as BBB with a stable outlook and its preferred stock as BB+. As of September 30, 2005, Moody's rated PNM's senior unsecured notes as Baa2 and its preferred stock as Ba1. S&P has assigned its A-2 corporate credit and short-term debt ratings to PNM's rated commercial paper program. Moody's has assigned its P-2 corporate credit and short-term debt ratings to PNM's rated commercial paper program.
In June 2005, TNMP filed an application with the NMPRC to become a borrower and issue notes of up to $100.0 million under the PNMR Facility. In July 2005, the NMPRC issued an order approving the application, SEC approval was received in September 2005 and TNMP was added as a borrower under the PNMR Facility in September 2005. Any borrowings made by TNMP under this sublimit are not guaranteed by PNMR. At October 28, 2005, TNMP had no outstanding borrowings under the PNMR Facility, but did have $2.0 million letters of credit outstanding, which reduces available capacity under the PNMR Facility.
TNMP's ability, if required, to access the capital markets at a reasonable cost and to provide for other capital needs is largely dependent upon its ability to earn a fair return on equity, its results of operations, its credit ratings, obtaining required regulatory approvals and financial and wholesale market conditions. Financing flexibility is enhanced by providing a high percentage of total capital requirements from internal sources and having the ability, if necessary, to issue long-term securities and to obtain short-term credit.
TNMP's credit outlook was considered stable by S&P and Moody's as of the date of this report. The Company is committed to maintaining or improving its investment grade ratings. As of September 30, 2005, S&P rated TNMP's senior unsecured notes at BBB. As of September 30, 2005, Moody's rated TNMP's senior unsecured notes at Baa3.
Contingent Provisions of Certain Obligations
PNMR, PNM and TNMP have a number of debt obligations and other contractual commitments that contain contingent provisions. Some of these, if triggered, could affect the liquidity of the Company. PNMR, PNM or TNMP could be required to provide security, immediately pay outstanding obligations or be prevented from drawing on unused capacity under certain credit agreements if the contingent requirements were to be triggered. The most significant consequences resulting from these contingent requirements are detailed in the discussion below.
130
The committed PNMR Facility contains a "ratings trigger," for pricing purposes only. If PNMR is downgraded or upgraded by the ratings agencies, the result would be an increase or decrease in interest cost, respectively. In addition, the PNMR Facility contains a contingent requirement that requires PNMR to maintain a debt-to-capital ratio, inclusive of off-balance sheet debt, of less than 65%. If PNMR's debt-to-capital ratio, inclusive of off-balance sheet debt, were to exceed 65%, it could be required to repay all borrowings under the PNMR Facility, be prevented from drawing on the unused capacity under the PNMR Facility, and be required to provide security for all outstanding letters of credit issued under the PNMR Facility.
PNM's standard purchase agreement for the procurement of gas for its retail customers contains a contingent requirement that could require PNM to provide security for its gas purchase obligations if the seller were to reasonably believe that PNM was unable to fulfill its payment obligations under the agreement.
The master agreement for the sale of electricity in the WSPP contains a contingent requirement that could require PNM to provide security if its debt were to fall below investment grade rating. The WSPP agreement also contains a contingent requirement, commonly called a material adverse change provision, which could require PNM to provide security if a material adverse change in its financial condition or operations were to occur.
The committed PNM Facility contains a "ratings trigger," for pricing purposes only. If PNM is downgraded or upgraded by the ratings agencies, the result would be an increase or decrease in interest cost, respectively. In addition, the PNM Facility contains a contingent provision that requires PNM to maintain a debt-to-capital ratio, inclusive of off-balance sheet debt, of less than 65%. If PNM's debt-to-capital ratio, inclusive of off-balance sheet debt, were to exceed 65%, PNM could be required to repay all borrowings under the PNM Facility, be prevented from drawing on the unused capacity under the PNM Facility, and be required to provide security for all outstanding letters of credit issued under the PNM Facility.
If a contingent requirement were to be triggered under the PNM Facility resulting in an acceleration of the outstanding loans under the PNM Facility, a cross-default provision in the PVNGS leases could occur if the accelerated amount is not paid. If a cross-default provision is triggered, the lessors have the ability to accelerate their rights under the leases, including acceleration of all future lease payments.
TNMP's borrowing availability under the committed PNMR Facility contains a "ratings trigger," for pricing purposes only. If TNMP is downgraded or upgraded by the ratings agencies, the result would be an increase or decrease in interest cost, respectively. In addition, the PNMR Facility contains a contingent requirement that requires TNMP to maintain a debt-to-capital ratio, inclusive of off-balance sheet debt, of less than 65%. If TNMP's debt-to-capital ratio, inclusive of off-balance sheet debt, were to exceed 65%, TNMP could be required to repay all borrowings under the PNMR Facility, be prevented from drawing on the unused capacity under the PNMR Facility, and be required to provide security for all outstanding letters of credit issued under the PNMR Facility.
131
PNMR has a universal shelf registration statement filed with the SEC for the issuance of debt securities, equity securities, preferred stock, purchase contracts, purchase contract units and warrants. As of September 30, 2005, PNMR had approximately $400.9 million of remaining unissued securities under this registration statement.
PNMR has entered into three fixed-to-floating interest rate swaps with an aggregate notional principal amount of $150.0 million. Under these swaps, PNMR receives a 4.40% fixed interest payment on the notional principal amount on a semi-annual basis and pays a floating rate equal to the six month LIBOR plus 58.15 basis points (0.5815%) on the notional amount through September 15, 2008. The initial floating rate was 1.91% and will be reset every six months. The floating rate was reset on September 15, 2005, to 4.60%. The swap is accounted for as a fair-value hedge with a negative fair-market value (liability position) of approximately $3.2 million as of September 30, 2005.
During October 2004, PNMR entered into two forward starting floating-to-fixed rate interest rate swaps with an aggregate notional principal amount of $100.0 million. These swaps became effective August 1, 2005 and terminate November 15, 2009. Under these swaps, PNMR receives a floating rate equal to the three month LIBOR rate on the notional principal amount and pays a fixed interest rate of 3.97% on the notional principal amount on a quarterly basis. The initial floating rate was set on August 1, 2005, at 3.69% and will be reset every three months.
Each purchase contract obligates Cascade to purchase, and PNMR to sell, at a purchase price of $25.00 in cash, shares of PNMR's common stock on or before November 16, 2008 (the "Purchase Contract Settlement Date"). Generally, the number of shares Cascade is obligated to purchase depends on the average closing price per share of PNMR's common stock over a 20-day trading period ending on the third trading day immediately preceding the Purchase Contract Settlement Date, subject to anti-dilution adjustments. If the average closing price for the 20-day trading period is equal to or greater than approximately $25.116 per share, the settlement rate will be 0.9954 shares of common stock. If the average closing price for the trading period is less than approximately $25.116 per share but greater than $20.93 per share, the settlement rate is equal to $25.00 divided by the average closing price of PNMR's common stock for the trading period. If the average closing price for the trading period is less than or equal to $20.93 per share, the settlement rate will be 1.1945 shares of common stock. Cascade has the option to settle its obligations under the purchase contracts at any time on or prior to the fifth business day immediately preceding the Purchase Contract Settlement Date. Prior to the Purchase Contract Settlement Date, the senior notes will be remarketed. If the remarketing is successful, the interest rate on the senior notes may change to a rate selected by the remarketing agent, and the maturity of the senior notes may be extended to a date selected by PNMR. If the remarketing of the senior notes is not successful, the maturity and interest rate of the senior notes will not change and holders of the equity units will have the option of putting their senior notes to PNMR to satisfy their obligations under the purchase contracts.
In March 2005, PNMR issued 3,910,000 shares of its common stock at $26.76 per share. PNMR received net proceeds from this offering, after deducting underwriting discounts and commissions and estimated expenses, of approximately $101.0 million. In addition, in March 2005, PNMR also completed a public offering of 4,945,000 equity units at 6.75% yielding net proceeds after fees of $239.6 million.
PNM has a universal shelf registration statement filed with the SEC for the issuance of debt securities, equity securities, preferred stock, purchase contracts, purchase contract units and warrants. As of September 30, 2005, PNM had approximately $200.0 million of remaining unissued securities registered under its shelf registration statement. The amount of senior unsecured notes that may be issued is not limited by the senior unsecured notes indenture. However, debt-to-capital requirements in certain of PNM's financial instruments and regulatory agreements could ultimately limit the amount of additional debt PNM could issue.
Depending on TNMP's future business strategy, capital needs and market conditions, TNMP could enter into additional long-term financings for the purpose of strengthening TNMP's balance sheet, funding growth and reducing its cost of capital. The Company continues to evaluate its investment and debt retirement options to optimize its financing strategy and earnings potential. The amount of senior unsecured notes that may be issued is not limited by the senior unsecured notes indenture. However, debt-to-capital requirements in certain of TNMP's financial instruments and regulatory agreements would ultimately limit the amount of additional debt TNMP would issue.
134
Capital Structure
PNMR's capitalization, including current maturities of long-term debt, at September 30, 2005 and December 31, 2004 is shown below:
Common Equity
44.0%
52.4%
Preferred Stock
0.4%
0.6%
Long-term Debt
55.6%
47.0%
Total Capitalization
100.0%
Total capitalization does not include as debt the present value of PNM's operating lease obligations for PVNGS Units 1 and 2, EIP and the Delta operating lease, which was approximately $172.2 million as of September 30, 2005 and $176.0 million as of December 31, 2004.
The change in PNMR's capitalization is due to the issuance of common stock and equity units in March 2005 and the acquisition of TNP on June 6, 2005. For additional information on the acquisition, refer to Note 2 - "TNP Acquisition," in the Notes to Consolidated Financial Statements. Total capitalization does not include the effect of the equity-linked securities issued to Cascade in October 2005. Refer to Note 6 - "Capitalization," in the Notes to Consolidated Financial Statements.
PNM's capitalization, including current maturities of long-term debt, at September 30, 2005 and December 31, 2004 is shown below:
50.1%
50.8%
49.3%
48.6%
135
TNMP's capitalization, including current maturities of long-term debt, at September 30, 2005 and December 31, 2004 is shown below:
59.4%
31.3%
40.6%
68.7%
The change in TNMP's capitalization is due to the acquisition of TNP on June 6, 2005 and the effects of purchase accounting.
Commitments and Contractual Obligations
PNMR, PNM and TNMP have contractual obligations for long-term debt, operating leases, purchase obligations and certain other long-term liabilities that were summarized in a table of contractual obligations in the 2004 Annual Reports on Forms 10-K. At September 30, 2005, PNMR's long-term debt increased by $247.3 million due to PNMR's issuance of equity-linked securities (see "Financing Activities" section above). There have been no significant changes to PNM's or TNMP's contractual obligations from December 31, 2004.
QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company uses derivative financial instruments to manage risk as it relates to changes in natural gas and electric prices, changes in interest rates and, historically, adverse market changes for investments held by the Company's various trusts. The Company also uses certain derivative instruments for wholesale power marketing transactions in order to take advantage of favorable price movements and market timing activities in the wholesale power markets. The following additional information is provided.
PNMR controls the scope of its various forms of risk through a comprehensive set of policies and procedures and oversight by senior level management and the PNMR Board. The Board's Finance Committee sets the risk limit parameters. The RMC, comprised of corporate and business segment officers and other managers, oversees all of the activities, which include commodity price, credit, equity, interest rate and business risks. The RMC has oversight for the ongoing evaluation of the adequacy of the risk control organization and policies. PNMR has a risk control organization, headed by a Risk Manager, which is assigned responsibility for establishing and enforcing the policies, procedures and limits and evaluating the risks inherent in proposed transactions, on an enterprise-wide basis.
The RMC's responsibilities specifically include: establishment of a general policy regarding risk exposure levels and activities in each of the business segments; authority to approve the types of instruments traded; authority to establish a general policy regarding counterparty exposure and limits; authorization and delegation of transaction limits; review and approval of controls and procedures; review and approval of models and assumptions used to calculate mark-to-market and risk exposure; authority to approve and open brokerage
and counterparty accounts; review of hedging and risk activities; and quarterly reporting to the Finance Committee and the PNMR Board on these activities.
The RMC also proposes risk limits, such as VaR and EaR, to the Finance Committee. The Finance Committee ultimately sets the Company's risk limits.
It is the responsibility of each business segment to create its own control procedures and policies within the parameters established by the Finance Committee. The RMC reviews and approves these policies, which are created with the assistance of the Corporate Controller, Director of Internal Audit and the Director of Financial Risk Management. Each business segment's policies address the following controls: authorized risk exposure limits; authorized instruments and markets; authorized personnel; policies on segregation of duties; policies on mark-to-market accounting; responsibilities for deal capture; confirmation procedures; responsibilities for reporting results; statement on the role of derivative transactions; and limits on individual transaction size (nominal value).
To the extent an open position exists, fluctuating commodity prices can impact financial results and financial position, either favorably or unfavorably. As a result, the Company cannot predict with certainty the impact that its risk management decisions may have on its businesses, operating results or financial position.
Commodity Risk
Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing open positions in the energy markets, primarily on a short-term basis. These risks fall into three different categories: price and volume volatility, credit risk of counterparties and adequacy of the control environment. The Company's operations subject to market risk routinely enter into various derivative instruments such as forward contracts, option agreements and price basis swap agreements to hedge price and volume risk on their purchase and sale commitments, fuel requirements and to enhance returns and minimize the risk of market fluctuations on the wholesale operations.
PNM's wholesale operations, including long-term contracts and short-term sales, are managed primarily through a net asset-backed marketing strategy, whereby PNM's aggregate net open forward contract position is covered by its forecasted excess generation capabilities. PNM is exposed to market risk if its generation capabilities were to be disrupted or if its retail load requirements were to be greater than anticipated. If PNM were required to cover all or a portion of its net open contract position as a result of the aforementioned unexpected situations, it would have to meet its commitments through market purchases. In addition, the wholesale operations utilize discrete market-based transactions to take advantage of opportunities that present themselves in the ordinary course of business. These positions are subject to market risk that is not mitigated by PNM's generation capabilities.
First Choice is responsible for energy supply related to the sale of electricity to retail customers in Texas. TECA contains no provisions for the specific recovery of fuel and purchased power costs. First Choice operates within a competitive marketplace; however, to the extent that it serves former TNMP customers under the provisions of the price-to-beat service, it has the ability to file with the PUCT to change the price-to-beat fuel factor twice each year, in the event of significant changes in natural gas prices. The rates charged to new
137
customers acquired by First Choice outside of TNMP's service territory are not regulated by the PUCT, but are negotiated with each customer. As a result, changes in fuel and purchased power costs will affect First Choice's operating results. First Choice is exposed to market risk to the extent that its retail rates or cost of supply fluctuates with market prices. First Choice's basic strategy is to minimize its exposure to fluctuations in market energy prices by matching fixed price sales contracts with fixed price supply.
Additionally, in connection with the issuance of a final stranded cost true-up order for TNMP, the PUCT will adjust First Choice's fuel factor portion of the price-to-beat downward if natural gas prices are below the prices embedded in the then-current rates. See Note 9 - "Regulatory and Rate Matters - Retail Competition, Price-to-Beat Fuel Factor and Price-to-Beat Base Rate Reset," in the Notes to Consolidated Financial Statements.
Accounting for Derivatives
Under the derivative accounting rules and the related accounting rules for energy contracts, the Company accounts for its various financial derivative instruments for the purchase and sale of energy differently based on management's intent when entering into the contract. Energy contracts that meet the definition of a derivative under SFAS 133 and do not qualify for a normal purchase or sale designation are recorded on the balance sheet at fair market value at each period end. The changes in fair market value are recognized in earnings unless specific hedge accounting criteria are met. Should an energy transaction qualify as a hedge under SFAS 133, fair market value changes from year to year are recognized on the balance sheet with a corresponding charge to other comprehensive income. Gains or losses are recognized when the hedged transaction settles. Derivatives that meet the normal sales and purchases exceptions within SFAS 133 are not marked to market but rather recorded in results of operations when the underlying transaction settles.
The following table shows First Choice's net fair value of mark-to-market energy contracts included in the balance sheet:
Mark-to-Market Energy Contracts:
Current asset
$2,109
Long-term asset
Total mark-to-market assets
2,605
Current liability
1,806
Total mark-to-market liabilities
Net fair value of mark-to-market energy contracts
$ 799
The mark-to-market energy transactions represent net assets at September 30, 2005 after netting all applicable open purchase and sale contracts.
The market prices used to value First Choice mark-to-market energy transactions are based on index prices and broker quotations. Generally, market data to value these transactions is available for the next 18-month period only; the remaining time period, referred to as the illiquid period, is valued using internally developed pricing data. As a result, the Company records liquidity reserves on these contracts for market gains and losses in the illiquid period, effectively limiting the mark-to-market valuation to a rolling 18-month period. The Company regularly assesses the validity and availability of pricing data for the illiquid period of its derivative transactions and adjusts its liquidity reserves, accordingly.
The following table provides detail of changes in First Choice operations' mark-to-market energy transactions' net asset or liability balance sheet position from one period to the next:
June 6 -
Sources of Fair Value Gain/(Loss):
Fair value at beginning of year
Amount realized on contracts delivered
during period
(56)
Changes in fair value
855
Net fair value at end of period
Net change recorded as mark-to-market
The following table provides the maturity of the net assets/(liabilities) of First Choice, giving an indication of when these mark-to-market amounts will settle and generate/(use) cash. The following values were determined using broker quotes:
Fair Value at September 30, 2005
Maturities
Less than
1 year
1-3 Years
4+ Years
Total
$ 303
$ 496
As of September 30, 2005, a decrease in market pricing of First Choice's mark-to-market energy transactions by 10% would have resulted in a decrease in net earnings of less than 1%. Conversely, an increase in market pricing of these transactions by 10% would have resulted in an increase in net earnings of less than 1%.
139
The following table shows PNM Wholesale's net fair value of mark-to-market energy contracts included in the balance sheet:
$ 9,288
$ 6,890
14,906
316
24,194
7,206
(8,336)
(5,007)
Long-term liability
(14,165)
(126)
(22,501)
(5,133)
$ 1,693
$ 2,073
The mark-to-market energy transactions represent net assets at September 30, 2005 and December 31, 2004 after netting all applicable open purchase and sale contracts.
The market prices used to value PNM Wholesale's mark-to-market energy transactions are based on index prices and broker quotations. Generally, market data to value these transactions is available for the next 18-month period only; the remaining time period, referred to as the illiquid period, is valued using internally developed pricing data. As a result, the Company records liquidity reserves on these contracts for market gains and losses in the illiquid period, effectively limiting the mark-to-market valuation to a rolling 18-month period. The Company regularly assesses the validity and availability of pricing data for the illiquid period of its derivative transactions and adjusts its liquidity reserves, accordingly.
The following table provides a detail of changes in PNM Wholesale's operations' mark-to-market energy transactions' net asset or liability balance sheet position from one period to the next:
$ 433
Changes in valuation methods
(227)
(1,675)
(3,118)
1,295
4,461
$ 1,549
$ (380)
$ 1,343
The following table provides the maturity of the net assets/(liabilities) of PNM Wholesale, giving an indication of when these mark-to-market amounts will settle and generate/(use) cash. The following values were determined using broker quotes:
$ 921
$ 545
$ 227
As of September 30, 2005, a decrease in market pricing of PNM Wholesale's mark-to-market energy transactions by 10% would have resulted in a decrease in net earnings of less than 1%. Conversely, an increase in market pricing of these transactions by 10% would have resulted in an increase in net earnings of less than 1%.
In the normal course of business, TNMP enters into commodity contracts in order to meet customer requirements. Criteria by which option-type and forward contracts for electricity can qualify for the normal purchase and sales exception has been defined by SFAS 133, as amended by SFAS No. 149, "Amendments of Statement 133 on Derivative Instruments and Hedging Activities." In accordance with these pronouncements, management has determined that TNMP's contracts for electricity qualify for the normal purchases and sales exception. Accordingly, TNMP does not account for its electricity contracts as derivatives.
Risk Management Activities
PNM's Wholesale Operations measure the market risk of its long-term contracts and wholesale activities using a VaR calculation to maintain the Company's total exposure within management-prescribed limits. The Company's VaR calculation reports the possible market loss for the respective transactions. This calculation is based on the transaction's fair market value on the reporting date. Accordingly, the VaR calculation is not a measure of the potential accounting mark-to-market loss. In 2005, the Company adopted the Monte Carlo simulation model of VaR. The Monte Carlo model utilizes a random generated simulation based on historical volatility to generate portfolio values. The Company continues to utilize the two-tailed confidence level at 99%. VaR models are relatively sophisticated. The quantitative risk information, however, is limited by the parameters established in creating the model. The instruments being evaluated may trigger a potential loss in excess of calculated amounts if changes in commodity prices exceed the confidence level of the model used. The VaR methodology employs the following critical parameters: volatility estimates, market values of open positions, appropriate market-oriented holding periods and seasonally adjusted correlation estimates. The Company's VaR calculation considers the Company's forward position for the next eighteen months. The Company uses a holding period of three days as the estimate of the length of time that will be needed to liquidate the positions. The volatility and the correlation estimates measure the impact of adverse price movements both at an individual position level as well as at the total portfolio level. The two-tailed confidence level established is 99%. For example, if VaR is calculated at $10.0 million, it is estimated at a 99% confidence level that if prices move against PNM's positions, the Company's pre-tax gain or loss in liquidating the portfolio would not exceed $10.0 million in the three days that it would take to liquidate the portfolio.
141
In 2005, the Company revised its methodologies for calculating VaR in order to improve its ability to measure and manage risk. As a result, the Company also revised its VaR limits to be consistent with the new methodologies. As previously discussed, the Company adopted the Monte Carlo statistical simulation approach. In addition, the Company redefined the types of transactions on which it measures VaR. The total VaR is now based solely on its merchant activities and excludes all effects from the retail operations and the joint dispatch model employed by the Company. The total VaR limit established is $18.0 million. For the nine months ended September 30, 2005, the average total VaR amount was $14.6 million, with high and low VaR amounts for the period of $29.2 million and $4.0 million, respectively. The total VaR amount at September 30, 2005 was $20.0 million. In addition, the Company defined a sub-set of the total VaR that captures all transactions that are not directly asset related and have economic risk. The VaR limit established for these transactions is $5.0 million. For the nine months ended September 30, 2005, the average VaR amount for these transactions was $1.2 million, with high and low VaR amounts for the period of $3.5 million and less than $0.1 million, respectively. The VaR amount for these transactions at September 30, 2005 was $1.9 million.
In 2004, the Company utilized the variance/covariance model of VaR, which is a probabilistic model that measures the risk of loss to earnings in market sensitive instruments. The variance/covariance model relies on statistical relationships to analyze how changes in different markets can affect a portfolio of instruments with different characteristics and market exposure. For the nine months ended September 30, 2004 the Company's average total VaR amount was $13.8 million, with high and low VaR amounts for the period of $21.6 million and $5.1 million, respectively. The total VaR amount at September 30, 2004 was $13.2 million. In the prior year the Company also measured VaR for a subset of transactions that were marked-to-market in accordance with SFAS 133. The VaR limit established for these transactions was $2.0 million. For the nine months ended September 30, 2004, the average VaR amount for these transactions was $0.3 million, with high and low VaR amounts for the period of $1.1 million and $130, respectively. The total VaR amount for these transactions as reported at September 30, 2004 was $0.4 million. Because of the nature of the Monte Carlo simulation method now utilized by the Company, reporting of the 2004 VaR amounts using the Company's new approach is neither practical nor representational of the Company's management of risk in 2004.
First Choice measures the market risk of its activities using an EaR calculation to maintain the Company's total exposure within management-prescribed limits. Because of its obligation to serve, First Choice must take its obligations to settlement. Accordingly, a measure that evaluates the settlement of First Choice's positions against earnings provides management with a useful tool to manage its portfolio. First Choice's EaR calculation reports the possible losses against forecasted earnings for its retail load and supply portfolio. This calculation is based on First Choice's forecasted earnings on the reporting date. The Company utilizes a Delta/Gamma approximation model of EaR. The Delta/Gamma model calculates a price change within a given time frame, correlation and volatility parameters for each price curve utilized in valuing the mark-to-market of each position to develop a change in value for any position. This process is repeated multiple times to calculate a standard deviation, which is used to arrive at an EaR
142
amount based on a certain confidence level. The model uses the Delta/Gamma approximation to model the optionality related to price-to-beat rate resets by both the Company and the PUCT as discussed above. First Choice utilizes the one-tailed confidence level at 95%. EaR models are relatively sophisticated. The quantitative risk information, however, is limited by the parameters established in creating the model. The instruments being evaluated may trigger a potential loss in excess of calculated amounts if changes in commodity prices exceed the confidence level of the model used. The EaR calculation considers the Company's forward position for the next twelve months and holds each position to settlement. The volatility and the correlation estimates measure the impact of adverse price movements both at an individual position level as well as at the total portfolio level. For example, if EaR is calculated at $10.0 million, it is estimated at a 95% confidence level that if prices move against First Choice's positions, the losses against the Company's forecasted earnings over the next twelve months would not exceed $10.0 million.
For the three months ended September 30, 2005, the average total EaR amount was $21.6 million, with high and low EaR amounts for the period of $22.0 million and $21.0 million, respectively. The total EaR amount at September 30, 2005 was $21.9 million.
In July 2005, the Finance Committee approved new risk measures for First Choice. These measures were designed to give First Choice management flexibility to execute its strategies to reduce the risk inherent in the portfolio and to take advantage of market opportunities in a controlled and limited fashion. The Company adopted an EaR limit of $25.0 million. Upon successful execution of First Choice's strategy to mitigate risk by locking in its floating supply costs at favorable prices, these limits are expected to be lowered to match the new risk profile. In addition, the Company adopted two new VaR measures to monitor the market based mitigation strategies of First Choice management. The first VaR limit is based on the same total retail load and supply portfolio as the EaR measure; however, the VaR measure is intended to capture the effects of changes in market prices over a 10 day holding period. This holding period is considered appropriate given the nature of First Choice's supply portfolio and the constraints faced by First Choice in the ERCOT market. The calculation utilizes the same Monte Carlo simulation approach described above at a 95% confidence level. This VaR limit was established at $7.5 million. The second VaR limit was established at $1.5 million for transactions that are subject to mark-to-market accounting as defined by SFAS 133 and SFAS 149. This calculation captures the effect of changes in market prices over a three day holding period and utilizes the same Monte Carlo simulation approach described above at a 95% confidence level.
The Company's risk measures are regularly monitored by the Company's RMC. The RMC has put in place procedures to ensure that increases in risk measures that exceed the prescribed limits are reviewed and, if deemed necessary, acted upon to reduce exposures. The VaR and EaR limits represent an estimate of the potential gains or losses that could be recognized on the Company's portfolios, subject to market risk, given current volatility in the market, and are not necessarily indicative of actual results that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ due to actual fluctuations in market prices, operating exposures, and the timing thereof, as well as changes to the underlying portfolios during the year.
143
Credit Risk
The Company is exposed to credit losses in the event of non-performance or non-payment by counterparties. The Company manages credit on a consolidated basis and uses a credit management process to assess and monitor the financial conditions of counterparties. Credit exposure is regularly monitored by the RMC. The RMC has put in place procedures to ensure that increases in credit risk measures that exceed the prescribed limits are reviewed and, if deemed necessary, acted upon to reduce exposures.
144
The following table provides information related to PNM Wholsale's credit exposure as of September 30, 2005. The Company does not hold any credit collateral as of September 30, 2005. The table further delineates that exposure by the credit worthiness (credit rating) of the counterparties and provides guidance as to the concentration of credit risk to individual counterparties PNM Wholesale may have. Also provided is an indication of the maturity of a Company's credit risk by credit ratings of the counterparties.
Schedule of PNM Wholesale Credit Risk Exposure September 30, 2005
Net
Number
Exposure
of
Credit
Counter-
Risk
parties
Rating (a)
>10%
(Dollars in thousands)
Investment grade
$66,263
$42,846
Non-investment grade
3,319
Internal ratings
12,048
$81,752
(a) The Rating included in "Investment Grade" are counterparties with a minimum S&P rating of BBB- or Moody's rating of Baa3. If the counterparty has provided a guarantee by a higher rated entity (e.g., its parent), determination is based on the rating of its guarantor. The category "Internal Ratings - Investment Grade" includes those counterparties that are internally rated as investment grade in accordance with the guidelines established in the Company's credit policy.
(b) TheNet Credit Risk Exposure is the net credit exposure to PNM from its Wholesale Operations. This includes long-term contracts, forward sales and short-term sales. The exposure captures the net amounts due to PNM from receivables/payables for realized transactions, delivered and unbilled revenues, and mark-to-market gains/losses (pursuant to contract terms). Exposures are offset according to legally enforceable netting arrangements and reduced by credit collateral. Credit collateral includes cash deposits, letters of credit and performance bonds received from counterparties. Amounts are presented before those reserves that are determined on a portfolio basis.
145
PNM Wholesale Maturity of Credit Risk Exposure As of September 30, 2005
Rating
2 Years
2-5 Years
>5 Years
$53,003
$10,279
$ 2,981
1,589
1,730
$66,762
$12,009
The Company provides for losses due to market and credit risk. PNM Wholesale credit risk with its largest counterparty as of September 30, 2005 and December 31, 2004 was $21.3 million and $26.2 million, respectively.
First Choice is subject to credit risk from non-performance by its supply counterparties to the extent these contracts have a mark-to-market value in the favor of First Choice. The Constellation power supply agreement established FCPSP, a bankruptcy remote special purpose entity, to hold all of First Choice's customer contracts and wholesale power and gas contracts. Constellation received a lien on accounts receivable, customer contracts, cash, and the equity of FCPSP as security for FCPSP's performance under the power supply agreement. The provisions of this agreement severely limit FCPSP's ability to secure power from alternate sources. Additionally, the terms of the security agreement do not require Constellation to post collateral for any mark-to-market balances in FCPSP's favor. At September 30, 2005, the supply contracted with Constellation was in a favorable mark-to-market position for FCPSP. When netted against amounts owed to Constellation, this exposure was approximately $36.5 million. The Constellation power supply agreement collateral provisions will continue until the expiration of the agreement on December 31, 2007.
First Choice has continued to experience a reduction in bad debt expense from its retail customers due to reduced customer receivables resulting partially from effective disconnect policies, increased collection activity and refined consumer credit and securitization policies. Bad debt expenses for the nine months ended September 30, 2005 and 2004 were $3.2 million and $6.3 million, respectively. First Choice expects bad debt expense to increase in the fourth quarter of 2005 due primarily to the continued increase in the price of natural gas and impacts from the Gulf Coast hurricanes, including waiver of customer deposits for hurricane victims.
146
PNM Gas Supply Hedging Activities
PNM hedges certain portions of natural gas supply contracts in order to protect its retail customers from adverse price fluctuations in the natural gas market. The financial impact of all hedge gains and losses, including the related costs of the program, is recoverable through the PGAC. As a result, earnings are not affected by gains and losses generated by these instruments.
In order to protect its natural gas customers from the risk of rising prices during the 2005-2006 heating season, in total, PNM plans to expend approximately $6.8 million in 2005 to purchase gas options that essentially cap the amount PNM would pay for each volume of gas subject to the options during the winter heating season. PNM expects to recover its option premiums as a component of the PGAC during the months of October 2005 through February 2006.
Interest Rate Risk
PNMR's senior notes issued as part of the equity-linked securities sold in March and October 2005 will be remarketed in 2008. If the remarketing is successful, the interest rate on the senior notes may change to a rate selected by the remarketing agent, and the maturity of the senior notes may be extended to a date selected by PNMR. If the remarketing of the senior notes is not successful, the maturity and interest rate of the senior notes will not change and holders of the equity units will have the option of putting their senior notes to PNMR to satisfy their obligations under the purchase contracts.
PNM has long-term debt which subjects it to the risk of loss associated with movements in market interest rates. The majority of PNM's long-term debt is fixed-rate debt, and therefore, does not expose PNM's earnings to a major risk of loss due to adverse changes in market interest rates. However, the fair value of all long-term debt instruments would increase by approximately 3.3%, or $33.9 million, if interest rates were to decline by 50 basis points from their levels at September 30, 2005. As of September 30, 2005, the fair value of PNM's long-term debt was approximately $1.02 billion as compared to a book value of $987.2 million. In general, an increase in fair value would impact earnings and cash flows to the extent not recoverable in rates if PNM were to re-acquire all or a portion of its debt instruments in the open market prior to their maturity.
During the three and nine months ended September 30, 2005, PNM contributed cash of approximately $1.5 million and $4.6 million, respectively, to other post retirement benefits for plan year 2005. The securities held by the trusts had an estimated fair value of $808.5 million as of September 30, 2005, of which approximately 28% were fixed-rate debt securities that subject PNM to risk of loss of fair value with movements in market interest rates. If rates were to increase by 50 basis points from their levels at September 30, 2005, the decrease in the fair value of the securities would be 2.9% or $5.5 million. PNM does not currently recover or return through rates any losses or gains on these securities. PNM, therefore, is at risk for shortfalls in its funding of its obligations due to investment losses. PNM does not believe that long-term
market returns over the period of funding will be less than required for PNM to meet its obligations. However, this belief is based on assumptions about future returns that are inherently uncertain.
TNMP has long-term debt which subjects it to the risk of loss associated with movements in market interest rates. The majority of TNMP's long-term debt is fixed-rate debt, and therefore, does not expose TNMP's earnings to a major risk of loss due to adverse changes in market interest rates. However, the fair value of all long-term debt instruments would increase by approximately 1.3%, or $5.6 million, if interest rates were to decline by 50 basis points from their levels at September 30, 2005. As of September 30, 2005, the fair value of TNMP's long-term debt was approximately $428.3 million as compared to a book value of $ 415.8 million. In general, an increase in fair value would impact earnings and cash flows to the extent not recoverable in rates if TNMP were to re-acquire all or a portion of its debt instruments in the open market prior to their maturity.
During the three and nine months ended September 30, 2005 and 2004, TNMP contributed cash of approximately $0.3 million and $0.7 million, respectively, to other postretirement benefits for plan year 2005. The securities held by the trusts had an estimated fair value of $86.6 million as of September 30, 2005, of which approximately 16.1% were invested in money market funds. TNMP does not currently recover or return through rates any losses or gains on these securities.
Equity Market Risk
Until October 2005, when the program was discontinued, PNMR had a cash management program that included a preferred stock dividend capture strategy and various absolute return strategies that had the objective of achieving returns higher than that associated with passive cash management plans and with bond-like volatility. PNMR's initial investment in its cash management program was $10.0 million and an additional $2.0 million was invested in February 2005. As of September 30, 2005 and December 31, 2004, the balance in this investment, including profits and interest, was $10.1 million and $10.6 million, respectively.
PNMRdetermined that one of its investments under this program, Wood River, had experienced a loss in market value. At September 30, 2005, PNMR wrote down the value of its investment in Wood River to zero and incurred a loss of approximately $3.6 million for the three and nine months ended September 30, 2005.
148
PNM contributes to trusts established to fund its share of the decommissioning costs of PVNGS and pension and other postretirement benefits. The trusts hold certain equity securities as of September 30, 2005. These equity securities also expose the Company to losses in fair value. Approximately 60% of the securities held by the various trusts were equity securities as of September 30, 2005. Similar to the debt securities held for funding decommissioning and certain pension and other postretirement costs, PNM does not recover or earn a return through rates on any losses or gains on these equity securities.
TNMP and its subsidiaries sponsor a defined benefit pension plan covering substantially all of its employees. TNMP also sponsors a health care plan that provides post retirement medical and death benefits. Contributions are made to trusts that fund both of these employee benefits. The trusts held a certain equity mutual fund as of September 30, 2005, which exposes TNMP to losses in fair value. Approximately 22% of the assets in the retiree medical and death benefit trusts were invested in an equity index mutual fund. Approximately 63% of the assets in the pension were invested in an equity index mutual fund as of September 30, 2005.
OTHER ISSUES FACING THE COMPANY
See Note 8 - "Commitments and Contingencies," in the Notes to Consolidated Financial Statements.
NEW ACCOUNTING STANDARDS
There have been no new accounting standards that materially affected the Company this period. See Note 1 - "Accounting Policies and Responsibility for Financial Statements - Stock Based Compensation," in the Notes to Consolidated Financial Statements for discussion of SFAS No. 123 (revised 2004), "Share Based Payment."
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS
Statements made in this filing that relate to future events or PNMR's, PNM's or TNMP's expectations, projections, estimates, intentions, goals, targets and strategies, are made pursuant to the Private Securities Litigation Reform Act of 1995. Readers are cautioned that all forward-looking statements are based upon current expectations and estimates and PNMR, PNM and TNMP assume no obligation to update this information.
Because actual results may differ materially from those expressed or implied by these forward-looking statements, PNMR, PNM and TNMP caution readers not to place undue reliance on these statements. PNMR's, PNM's and TNMP's business, financial condition, cash flow and operating results are influenced by many factors, which are often beyond their control, that can cause actual results to differ from those expressed or implied by the forward-looking statements. These factors include:
The potential unavailability of cash at TNP and its subsidiaries,
The risk that TNP and its subsidiaries will not be integrated successfully into PNMR,
The risk that the benefits of the TNP acquisition will not be fully realized or will take longer to realize than expected,
Disruption from the TNP acquisition making it more difficult to maintain relationships with customers, employees, suppliers or other third parties,
The outcome of litigation with SW Acquisition relating to the TNP acquisition,
The outcome of any appeals of the PUCT order in the stranded cost true-up proceeding or the acquisition proceeding,
The ability of First Choice to attract and retain customers,
Changes in ERCOT protocols,
Changes in the cost of power acquired by First Choice,
Collections experience,
Insurance coverage available for claims made in litigation,
Fluctuations in interest rates,
Weather (including impacts of the hurricanes in the Gulf Coast region),
Water supply,
Changes in fuel costs,
Availability of fuel supplies,
The effectiveness of risk management and commodity risk transactions,
Seasonality and other changes in supply and demand in the market for electric power,
Variability of wholesale power prices,
Volatility in market liquidity,
Changes in the competitive environment in the electric and natural gas industries,
The performance of generating units and transmission systems,
The market for electrical generating equipment,
The ability to secure long-term power sales,
The risks associated with completion of construction of Luna, including construction delays and unanticipated cost overruns,
State and federal regulatory and legislative decisions and actions,
The outcome of legal proceedings,
Changes in applicable accounting principles,
The performance of state, regional and national economies, and
The other factors described in "Risk Factors" in this report.
See also "Quantitative and Qualitative Disclosure About Market Risk" above for information about the risks associated with PNMR's, PNM's and TNMP's use of derivative financial instruments.
SECURITIES ACT DISCLAIMER
Certain securities issued in connection with the TNP acquisition transaction and commercial paper described in this report have not been registered under the Securities Act of 1933, as amended, or any state securities laws and may not be reoffered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act of 1933 and applicable state securities laws. This report does not constitute an offer to sell or the solicitation of an offer to buy any securities.
150
RISK FACTORS
The business and financial results of PNMR, PNM and TNMP are subject to a number of risks and uncertainties, including those set forth below and under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this report. This discussion incorporates potential risks for PNMR, PNM and TNMP.
PNMR may fail to successfully integrate acquisitions, including TNP, into its other businesses or otherwise fail to achieve the anticipated benefits of pending and future acquisitions.
As part of PNMR's growth strategy, PNMR is pursuing, and intends to continue to pursue, a disciplined acquisition strategy. While PNMR expects to identify potential synergies, cost savings, and growth opportunities prior to the acquisition and integration of acquired companies or assets, PNMR may not be able to achieve these anticipated benefits due to, among other things:
delays or difficulties in completing the integration of acquired companies or assets,
higher than expected costs or a need to allocate resources to manage unexpected operating difficulties,
diversion of the attention and resources of its management,
reliance on inaccurate assumptions in evaluating the expected benefits of a given acquisition,
inability to retain key employees or key customers of acquired companies, and
assumption of liabilities unrecognized in the due diligence process.
With respect to the TNP acquisition, PNMR cannot assure that it will be able to successfully integrate TNP with PNMR 's current businesses. The integration of TNP with PNMR 's other businesses will present significant challenges and, as a result, PNMR may not be able to operate the combined company as effectively as expected. Also, even if PNMR manages to realize greater than anticipated benefits from the integration of TNP into its business, PNMR's regulated subsidiaries may be required by their regulators to return these benefits to ratepayers. In connection with the Texas and New Mexico settlements relating to the TNP acquisition, for example, TNMP agreed to provide ratepayers in Texas and New Mexico with rate credits over various periods of time resulting from anticipated synergy savings from the acquisition. PNMR may also fail to achieve the anticipated benefits of the acquisition as quickly or as cost-effectively as anticipated or may not be able to achieve those benefits at all.
While PNMR expects that this acquisition will be accretive to earnings and cash flow in the first full year of operation after the transaction is completed, this expectation is based on important assumptions, including assumptions related to interest rates, market prices for power, its ability to achieve operational benefits from operating the companies as a unified operation and the number of First Choice and TNMP customers that PNMR will be able to retain, which may ultimately be incorrect. In addition, the agreement TNMP has entered into with the PUCT staff and others relating to the TNP acquisition includes a two-year electric rate freeze and a $13.0 million annual rate reduction in TNMP's retail delivery rates effective May 1,
2005, which could adversely affect profitability if costs at TNMP are not controlled. Additionally, the agreement entered into with the NMPRC staff and others provides TNMP's New Mexico electric customers with a three-phase 15% rate reduction to begin January 2006 and end December 2010. As a result, if PNMR is unable to integrate its businesses with TNP effectively or achieve the benefits anticipated, PNMR's business, financial position, results of operations and liquidity may be materially adversely affected.
PNMR, PNM and TNMP are subject to complex government regulation, which may have a negative impact on their business, financial position and results of operations.
PNMR, PNM and TNMP are subject to comprehensive regulation by several federal, state and local regulatory agencies, which significantly influences their operating environment and may affect their ability to recover costs from utility customers. In particular, the NMPRC, the PUCT, the SEC, the FERC, the NRC, the EPA, ERCOT, the NMED and the TCEQ regulate many aspects of their utility operations, including siting and construction of facilities, conditions of service, the issuance of securities, and the rates that the regulated entities can charge customers. PNMR, PNM and TNMP are required to have numerous permits, approvals and certificates from these agencies to operate their business. The rates that PNM and TNMP are allowed to charge for their retail services significantly influence PNMR's and those subsidiaries' business, financial position, results of operations and liquidity. Due to pending federal regulatory reforms, the public utility industry continues to undergo change.
The Energy Policy Act of 2005 was enacted into law in August 2005. The legislation covers many areas, including the items set forth in Note 9 - "Regulatory and Rate Matters," in the Notes to the Consolidated Financial Statements and elsewhere in this report. The Energy Policy Act of 2005 requires several rule makings by the FERC and other governmental agencies in order to implement its provisions. PNMR is in the process of evaluating the effect of the Energy Policy Act of 2005.
PNMR and its subsidiaries are unable to predict the impact on their business and operating results from the future regulatory activities of any agency that regulates them or from the implementation of the Energy Policy Act of 2005. Changes in regulations or the imposition of additional regulations may require PNMR and its regulated subsidiaries to incur additional expenses or change business operations, and therefore may have an adverse impact on PNMR's and those subsidiaries' results of operations.
PNM's retail electric rate reduction and retail electric rate freeze, and the New Mexico settlement relating to the TNP acquisition, could adversely affect its profit margin if it does not control costs.
With NMPRC approval, PNM agreed to decrease its retail electric rates by 6.5% in two phases as follows: 4% effective September 1, 2003, and an additional 2.5% effective September 1, 2005. PNM also agreed to freeze these reduced retail electric rates through December 31, 2007. PNM's costs, however, are not frozen. In addition, the TNP acquisition settlement in New Mexico provides resolution on how synergy savings will be allocated among PNM's gas and electric customers. Pursuant to the TNP acquisition stipulation in New Mexico:
PNM's 413,000 electric customers will receive rate credits totaling $4.6 million or nearly $1.84 million annually over a 30-month period beginning January 2008.
152
PNM's 471,000 gas customers will receive $4.3 million in rate credits over five years, or $860,000 annually, beginning June 6, 2005. Thus, PNM's ability to maintain its profit margins depends upon increased demand for electricity and PNM's efforts to control costs incurred in supplying that electricity, including, in particular, its coal costs.
PNM does not have the benefit of a fuel adjustment clause for its retail electric operations that would allow it to recover increased fuel and purchased power costs from customers. Therefore, to the extent that PNM has not hedged its fuel and power costs, it is exposed to changes in fuel and power prices to the extent fuel for its electric generating facilities and power must be purchased on the open market in order for it to serve its retail electric customers. PNM anticipates being able to reduce base fuel costs as a result of its revised coal contract relating to the new underground mine serving SJGS. However, if the anticipated base fuel cost savings do not occur because of problems at the new mine or if PNM cannot control other operating expenses, the retail electric rate freeze may decrease PNM's profit margin. The retail electric rate freeze will also affect PNM's ability to earn a return or recover from its customers costs associated with investments in generation, transmission and distribution facilities since it will not be able to increase retail electric rates to recover those costs until at least after the end of the rate freeze. For example, in connection with the electric retail rate freeze stipulation, PNM agreed to invest $60.0 million per year through 2007 in gas and electric utility infrastructure, increasing to $64.0 million per year after PNM and TNMP are integrated. If future recovery of these costs ceases to be probable, PNM would be required to record a charge to earnings in the period for the portion of the costs that were determined not to be recoverable. The electric retail rate freeze stipulation does, however, allow PNM to seek a general rate adjustment for certain changes in environmental or tax laws.
PNMR and PNM are not able to predict what rate treatment PNM will receive following the expiration of the retail electric rate freeze in New Mexico. Some of the factors that influence rates are largely outside their control. In response to competitive, economic, political, legislative and/or regulatory pressures, PNM may have to agree to further rate freezes, rate refunds or rate reductions, any or all of which could have a significant adverse effect on PNMR's and PNM's business, financial position, results of operations and liquidity.
The impact from the TNP acquisition settlements could adversely affect TNMP's profit margin if TNMP does not control costs.
The TNP acquisition settlements for TNMP in Texas and New Mexico provide for the following:
a two-year electric rate freeze that includes a $13.0 million annual rate reduction in TNMP's retail delivery rates effective May 1, 2005,
a $6.0 million synergy savings credit amortized over 24 months effective after the closing of the transaction,
a three-phase rate reduction totaling 15%, beginning January 2006 and ending December 2010, provides for TNMP's electric customers in southern New Mexico. The rate reduction, which includes TNMP's annual synergy-savings allocation will lower TNMP electric rates by $9.6 million in the first year, and
maintaining PNM as the power supplier for TNMP's New Mexico needs through 2010.
153
In addition, as part of the New Mexico settlement relating to the TNP acquisition, TNMP's current fuel and purchased power adjustment clauses will be eliminated no later than March 31, 2006. Also, the New Mexico settlement requires the integration of TNMP's New Mexico assets into PNM effective January 1, 2007. The companies, however, will maintain separate rates through 2010.
PNMR and TNMP are not able to predict what rate treatment TNMP will receive following the expiration of the retail electric rate provisions in New Mexico. Some of the factors that influence rates are largely outside their control. In response to competitive, economic, political, legislative and/or regulatory pressures, TNMP may have to agree to further rate freezes, rate refunds or rate reductions, any or all of which could have a significant adverse effect on PNMR's and TNMP's business, financial position, results of operations and liquidity.
The ability of First Choice to attract and retain customers and its ability to mitigate the fluctuation in costs of energy supply could have a significant adverse effect on PNMR's business, financial position, results of operations and liquidity.
In 2002, retail competition began in Texas under the provisions of Senate Bill 7. Prior to 2002, TNMP operated as an integrated utility in Texas. In accordance with Senate Bill 7 and in compliance with a plan approved by the PUCT, TNMP separated its Texas utility operations into three components: (1) an unregulated retail sales business operated by First Choice; (2) a regulated power transmission and distribution business operated by TNMP and (3) power generation, a business which TNMP is no longer engaged in.
As a result of the acquisition of TNP, PNMR is exposed to competition in the unregulated Texas retail electricity market through First Choice, which serves customers at price-to-beat rates and customers at competitive rates. In order to compete effectively in the Texas retail electricity market, First Choice must be able to attract and retain customers on the basis of cost and service, while managing the cost of its energy supply. The ability of First Choice to compete successfully in the Texas market could have a significant effect on PNMR's business, financial position, results of operations and liquidity.
PNM is currently the subject of several regulatory proceedings and named in multiple lawsuits with respect to PNM's participation in the United States' Western energy markets.
The FERC is conducting industry-wide proceedings and investigations related to the alleged dysfunctions of the organized California market and the Pacific Northwest market during 2000 and 2001.
In March 2003, the FERC issued an order substantially adopting the ALJ's findings in the December 2002 decision, but requiring a change to the formula used to calculate refunds. The FERC raised concerns that the indices for California gas prices, a major element in the refund formula, had been subject to potential manipulation and were unverifiable. The effect of this change would be to increase PNM's refund liability. In October 2003, the FERC issued its order on rehearing in which it affirmed its decision to change the gas price indices used to calculate the refund amounts. This has the effect of increasing the Company's amount of refund. The precise amounts, however, will not be certain until the Cal ISO and Cal PX recalculate the refund amounts. In a report filed by the Cal ISO in March 2005, the Cal ISO indicated that the Cal PX had concluded its recalculation of the adjustments for hourly price mitigation. The Cal ISO is waiting to receive audited fuel cost information from market participants as a result of the fuel cost proceedings currently pending at the FERC before finalizing its recalculated refund amounts. In August 2005, the FERC issued an order setting out the process by which sellers into the Cal ISO and Cal PX markets could make their cost recovery filings pursuant to the FERC's prior orders that indicated sellers would get the opportunity to submit evidence demonstrating that the refund methodology creates a revenue shortfall for their transactions during the refund period. Included in PNM's submittal were objections to the limited amount of time the FERC allowed for sellers to complete their respective submittals, and the FERC's arbitrary decision to allow only marketers and not load serving entities such as PNM to include a return component in their cost filings. PNM participated with other competitive sellers to request rehearing of these issues before the FERC. In September 2005, PNM made its cost recovery filing identifying its costs associated with sales into the California Cal ISO and Cal PX markets during the refund period. PNM's cost recovery filing is still pending before FERC. In addition, the Company has engaged in discussions with California parties based upon a template provided by FERC, but is unable to predict whether settlement will be reached.
In September 2004, the Ninth Circuit issued its decision in one of the lead appellate cases addressing the FERC's refund order. The Ninth Circuit upheld the FERC's authority to
155
establish the market-based rate framework under the Federal Power Act, but held that the FERC violated its administrative discretion by declining to investigate whether it should order refunds from sellers who failed to provide transaction-specific reports to the FERC as required by its rules. The Ninth Circuit determined that the FERC has the authority to order refunds for these transactions if it elects to do so and remanded the case to the FERC for further proceedings, including a determination as to whether additional refunds are appropriate. PNM participated with other competitive sellers requesting rehearing by the Ninth Circuit, which is still pending. Additional appeals are still pending before the Ninth Circuit, includingCPUC vs FERC, a case addressing the scope of market transactions subject to refund. PNM has participated in this appeal as one of the members of the competitive sellers group. The Company cannot predict the ultimate outcome of any FERC proceeding that may result from these appeals, or whether PNM will be ultimately directed to make any additional future refunds as the result of the decision; however, the Company has recorded a reserve for this contingency.
In addition to the California refund proceedings, Puget Sound Energy, Inc. filed a complaint at the FERC alleging that spot market prices in the Pacific Northwest wholesale electric market were unjust and unreasonable. In September 2001, the ALJ issued a recommended decision and declined to order refunds associated with wholesale electric sales in the Pacific Northwest. In a ruling similar to the one issued in the California refund proceeding, the FERC allowed additional discovery to take place and the submission of additional evidence in the case in March 2003. In June 2003, the FERC issued an order terminating the proceeding and adopting the ALJ's recommendation that no refunds should be ordered. Several parties in the proceeding filed requests for rehearing and in November 2003, the FERC denied rehearing and reaffirmed its prior ruling that refunds were not appropriate for spot market sales in the Pacific Northwest during the first half of 2001. In November 2003, the Port of Seattle filed an appeal of the FERC's order denying rehearing in the Ninth Circuit, which is still pending. As a participant in the proceedings before the FERC, PNM is also participating in the appeal proceedings. The Ninth Circuit had originally scheduled oral arguments in the appeal for September 2005, but subsequently continued the oral argument after moving the case to a different panel of judges than those originally assigned. The Company is unable to predict the ultimate outcome of this appeal, or whether PNM will ultimately be directed to make any refunds.
In March 2002, the California Attorney General filed a complaint with the FERC against numerous sellers regarding prices for wholesale electric sales into the Cal ISO and Cal PX markets and to the California Department of Water Resources. PNM was among the sellers identified in this complaint and filed its answer and motion to intervene. In its answer, PNM defended its pricing and challenged the theory of liability underlying the California Attorney General's complaint. In May 2002, the FERC entered an order denying the California Attorney General's request to initiate a refund proceeding, but directed sellers, including PNM, to comply with additional reporting requirements with regard to certain wholesale power transactions. PNM has made filings required by the May 2002 order. The California Attorney General filed a petition for review in the Ninth Circuit. PNM intervened in the Ninth Circuit appeal and participated as a party in that proceeding. As noted above, in September 2004, the
156
Ninth Circuit issued its decision upholding the FERC's authority to establish the market-based rate framework under the Federal Power Act, but held that the FERC violated its administrative discretion by declining to investigate whether it should order refunds from sellers who failed to provide transaction-specific reports to the FERC as required by its rules. The Ninth Circuit determined that the FERC has the authority to order refunds for these transactions if it elects to do so and remanded the case back to the FERC for further proceedings, including a determination as to whether additional refunds are appropriate. PNM participated with other competitive sellers requesting rehearing en banc by the Ninth Circuit, which is still pending. The Company cannot predict the ultimate outcome of the FERC proceeding on remand, or whether PNM will be ultimately directed to make any additional refunds as the result of the decision.
In June 2004, PNM received notice that PNM has been included in a list of 56 defendants that have been sued by the City of Tacoma Department of Public Utilities in federal district court in the State of Washington. PNM has been listed in a class of defendants referred to as the "Trading Defendants", who allegedly engaged in buying, selling and marketing power in California and other locations in the Western United States. The complaint alleges the Trading Defendants acted in concert among themselves and with "Non-Defendant Trading Co-Conspirators" that were engaged in conduct that amounted to market manipulations, which the complaint defines as a pattern of activities that had the purpose and effect of creating the impression that the demand for power was higher, the supply of power was lower, or both, than was in fact the case. The complaint identified specific conduct that allegedly amounted to market manipulations, including the submission of false information and misrepresentation regarding load schedules, bids, power supply, transmission congestion, source and destination of energy, the supply and provision of energy and ancillary services. The complaint alleged the activities of the Trading Defendants, along with "Generator Defendants", who are defined as generators who generated power for sale into California and other Western markets, and the co-conspirators, resulted in substantially increased prices for energy in the Pacific Northwest spot market in excess of what otherwise would have been the price absent such unlawful acts, in violation of antitrust laws. The complaint asserted damages in excess of $175.0 million from the multiple defendants. There have been three recent Ninth Circuit decisions that, collectively, appear to make Plaintiffs' case more difficult to prevail. As a result, PNM joined a motion to dismiss the City of Tacoma Department of Public Utilities complaint given Ninth Circuit precedent. In a decision issued in February 2005, the district court judge in the case granted defendants' motion to dismiss. As a result, the antitrust lawsuit against PNM filed by the City of Tacoma Department of Public Utilities was dismissed. In March 2005, the City of Tacoma Department of Public Utilities filed an appeal in the Ninth Circuit contesting the district court's decision to dismiss the complaint. PNM participated in the appeal in support of the dismissal and joined in defendants' brief filed in the Ninth Circuit, as well as a motion for summary affirmance. The appeal and defendants' motion for summary affirmance of the district court is pending before the Ninth Circuit and the Company cannot predict the outcome of this appeal, or whether PNM will be required to make any refunds or pay damages as a result of this litigation.
There are inherent risks in the operation of nuclear facilities, such as environmental, health and financial risks and the risk of terrorist attack.
157
PNM has a 10.2% undivided interest in PVNGS, with portions of its interests in Units 1 and 2 held under leases. PVNGS is subject to environmental, health and financial risks such as the ability to dispose of spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, potential liabilities arising out of the operation of these facilities, and the costs of securing the facilities against possible terrorist attacks and unscheduled outages due to equipment and other problems. PNM maintains nuclear decommissioning trust funds and external insurance coverage to minimize its financial exposure to some of these risks; however, it is possible that damages could exceed the amount of insurance coverage. Although the decommissioning trust funds are designed to provide adequate funds for decommissioning at the end of the expected life of the PVNGS units, there is the risk of insufficient decommissioning trust funds in the event of early decommissioning of the units.
The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. In addition, if a serious nuclear incident were to occur at PVNGS, it could materially and adversely affect PNM's and PNMR's business, financial position, results of operations and liquidity. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. Each PVNGS lease describes certain events, including "Events of Loss" or "Deemed Loss Events", the occurrence of which could require PNM to, among other things, (i) pay the lessor and the equity investor, in return for the investor's interest in PVNGS, cash in the amount provided in the lease and (ii) assume debt obligations relating to the PVNGS lease. The "Events of Loss" generally relate to casualties, accidents and other events at PVNGS, which would severely, adversely affect the ability of the operating agent, APS, to operate, and the ability of PNM to earn a return on its interests in, PVNGS. The "Deemed Loss Events" consist mostly of legal and regulatory changes (such as changes in law making the sale and leaseback transactions illegal, or changes in law making the lessors liable for nuclear decommissioning obligations). PNMR and PNM believe that the probability of such "Events of Loss" or "Deemed Loss Events" occurring is remote for the following reasons: (i) to a large extent, prevention of "Events of Loss" and some "Deemed Loss Events" is within the control of the PVNGS participants, including PNMR, and the PVNGS operating agent, through the general PVNGS operational and safety oversight process and (ii) with respect to other "Deemed Loss Events," which would involve a significant change in current law and policy, they are unaware of any pending proposals or proposals being considered for introduction in Congress, or in any state legislative or regulatory body that, if adopted, would cause any of those events.
PNMR's and its electric subsidiaries' financial performance may be adversely affected if their power plants and transmission and distribution system are not successfully operated.
PNMR's and its electric subsidiaries' financial performance depends on the successful operation of their generation, transmission and distribution assets. Unscheduled or longer than expected maintenance outages, other performance problems with the electric generation assets, severe weather conditions, accidents and other catastrophic events, disruptions in the delivery of fuel and other factors could reduce its excess generation capacity and therefore limit the electric subsidiaries' ability to opportunistically sell excess power in the wholesale market. Diminished generation capacity could also result in the aggregate net open forward electric sales position being larger than forecasted generation capacity. If this were to occur, purchases
158
of electricity in the wholesale market would be required under contracts priced at the time of execution or, if in the spot market, at the then-current market price. There can be no assurance that sufficient electricity would be available at reasonable prices, or at all, if such a situation were to occur. Failures of transmission or distribution facilities may also cause interruptions in the services the electric subsidiaries provide. These potential generation, distribution and transmission problems, and any potentially related service interruptions, could result in lost revenues and additional costs.
PNMR's, PNM's and TNMP's counterparties may not meet their obligations.
PNMR and its operating subsidiaries are exposed to risk that counter parties, which owe them money, energy or other commodities or services, will not be able to perform their obligations. The possibility that certain counter parties may fail to perform their obligations has increased due to financial difficulties, in some cases brought on by improper or illegal accounting and business practices, affecting some participants in the energy industry. Should the counterparties to these arrangements fail to perform, PNMR or its affected subsidiary might be forced to honor the underlying commitment at then-current market prices. In such event, PNMR or the affected subsidiary might incur losses in addition to amounts, if any, already paid to the counter parties.
The operations of PNMR and its operating subsidiaries are subject to risks beyond their control that may reduce their revenues.
PNMR's and its operating subsidiaries' revenues are affected by the demand for electricity and natural gas. That demand can vary greatly based upon:
weather conditions, including hurricanes, seasonality and temperature extremes,
fluctuations in economic activity and growth in PNMR's service area and the Western region of the United States,
the extent of additional energy available from current or new competitors, and
the ability of First Choice to attract and retain customers.
Weather conditions will impact the revenues that PNMR and its operating subsidiaries obtain from electric wholesale sales. Very warm and very cold temperatures, especially for prolonged periods, can dramatically increase the demand for electricity for cooling and heating, respectively, as opposed to the effect of more moderate temperatures. Very warm temperatures inside the subsidiary's service territory reduce the amount of power available to sell on the wholesale market.
Drought conditions in New Mexico generally, and especially in the Four Corners region, in which the San Juan Generating Station and the Four Corners Generating Station are located, may affect the water supply for PNM's generating plants. If adequate precipitation is not received in the watershed that supplies the Four Corners areas, PNM may have to decrease generation at these plants, which would reduce PNM's ability to sell excess power on the wholesale market and reduce its revenues. As such, if the drought conditions continue or regulators or legislators take action to limit the PNM's supply of water, PNM's and PNMR's business may be adversely impacted. Although PNM has been able to maintain adequate access to water in the past, PNM cannot be certain that it will be able to do so in the future.
159
An inability to raise capital could limit PNMR's ability to execute its growth strategy and finance its capital requirements, which could adversely affect PNMR's business, financial position, results of operations and liquidity.
PNMR and its operating subsidiaries rely on access to both short-term money markets and longer-term capital markets as a source of liquidity for any capital requirements not satisfied by the cash flow from our operations, which could include capital requirements for energy infrastructure investments and funding new projects. If PNMR and its operating subsidiaries are not able to access capital at competitive rates or at all, PNMR's ability to implement its growth strategy and its ability to finance capital requirements, if needed, will be limited. Market disruptions or any downgrade of PNMR's or its operating subsidiaries' credit rating may increase the cost of borrowing or adversely affect their ability to raise capital through the issuance of securities or other borrowing arrangements, which could have a material adverse effect on their business, financial position, results of operations and liquidity. These disruptions could include:
an economic downturn,
changes in capital market conditions generally,
the bankruptcy of an unrelated energy company,
increased market prices for electricity and gas,
terrorist attacks or threatened attacks on facilities of PNMR's operating subsidiaries or those of unrelated energy companies, and
deterioration in the overall health of the utility industry.
A significant reduction in the credit ratings of PNMR or its operating subsidiaries could materially and adversely affect their business, financial position, results of operations and liquidity.
PNMR, PNM and TNMP cannot be sure that any of their current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency. Any downgrade:
could increase borrowing costs, which would diminish financial results,
could require payment of a higher interest rate in future financings and the potential pool of investors and funding sources could decrease,
could increase borrowing costs under certain of existing credit facilities,
could also require the provision of additional support in the form of letters of credit or cash or other collateral to various counterparties,
could limit access to or increase the cost of access to the commercial paper market, and
below investment grade credit ratings would also require approvals from the NMPRC for new wholesale plant projects and for continuing to participate in wholesale plant projects of more than a certain dollar value and under certain conditions.
The ratings from rating agencies reflect only the views of such rating agencies and are not recommendations to buy, sell or hold our securities. Each rating should be evaluated
160
independently of any other rating. Any downgrade or withdrawal of PNMR's, PNM's or TNMP's current ratings may have an adverse effect on the market price of their outstanding debt.
Costs of environmental compliance, liabilities and litigation could exceed PNMR's and its operating subsidiaries' estimates which could adversely affect their business, financial position, results of operations and liquidity.
Compliance with federal, state and local environmental laws and regulations may result in increased capital, operating and other costs, including remediation and containment expenses and monitoring obligations. PNMR, PNM and TNMP cannot predict how they would be affected if existing environmental laws and regulations were revised, or if new environmental laws and regulations seeking to protect the environment were adopted, but any such changes could increase their financing requirements or otherwise adversely affect their business, financial position, results of operations and liquidity. Revised or additional laws and regulations could also result in additional operating restrictions on their facilities or increased compliance costs that may not be fully recoverable in rates, thereby reducing net income. For example, any future changes in the interpretation of the Clean Air Act's new source review provisions could potentially increase operating and maintenance costs substantially. Similarly, in March 2005, the EPA adopted the Clear Air Act Mercury Rule, which is intended to reduce mercury emissions from coal-fired generation plants. PNMR and PNM cannot be certain how this rule will affect them.
In addition, PNM or TNMP may be designated as a responsible party for environmental clean-up at a site identified by a regulatory body. PNMR, PNM and TNMP cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up and compliance costs, and the possibility that changes will be made to the current environmental laws and regulations. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. Failure to comply with environmental laws and regulations, even if caused by factors beyond PNM's or TNMP's control, may result in the assessment of civil or criminal penalties and fines.
PNMR's business, results of operations and financial position may be adversely affected if PNMR and its operating subsidiaries do not successfully compete for wholesale customers and generation plant acquisition opportunities. Wholesale plants will be exposed to price risk to the extent they must compete for the sale of energy and capacity.
The electric utility industry has experienced a substantial increase in competition at the wholesale level, caused by changes in federal law and regulatory policy. As a result of the Public Utility Regulatory Policies Act of 1978 and the Energy Policy Act of 1992, competition in the wholesale electricity market has greatly increased due to a greater participation by traditional electricity suppliers, non-utility generators, independent power producers, wholesale power marketers and brokers, and due to the trading of energy futures contracts on various commodities exchanges. In 1996, the FERC issued new rules on transmission service to facilitate competition in the wholesale market on a nationwide basis. The rules give greater flexibility and more choices to wholesale power customers. Also, in July 2002, the FERC issued a notice of proposed rulemaking (which has not yet been adopted) related to open access transmission service and standard electricity market design.
161
As a result of the changing regulatory environment and the relatively low barriers to entry (which include, in addition to open access transmission service, relatively low construction costs for new generating facilities), PNMR expects competition to steadily increase. This increased competition could affect load forecasts, acquisition opportunities and wholesale energy sales and related revenues. Given that during 2004, PNM's sales in the wholesale electric market accounted for approximately 62% of our total MWh sales, the impact of these changes on PNMR's and PNM's financial results could be material. The effect on their business, results of operations and financial position could vary depending on the extent to which:
PNMR and its operating subsidiaries are able to acquire additional generation to compete in the wholesale market,
new opportunities are created for the expansion of wholesale load, and
current wholesale customers elect to purchase from other suppliers after existing contracts expire.
PNM's long-term contracts to supply power expire from 2006 through 2020. PNM's ability to renew these contracts at terms comparable to those currently in place is dependent upon prevailing market conditions at the time of negotiations.
To the extent electric capacity generated by wholesale plants is not under contract to be sold or committed to serving its retail electric load, either now or in the future, the business, results of operations and financial position of PNMR and PNM will generally depend on the prices that can be obtained for energy and capacity in New Mexico and adjacent markets. Among the factors that would influence these prices, all of which are beyond PNMR's and PNM's control to a significant degree, are those described in the next risk factor.
PNMR and its operating subsidiaries may not be able to mitigate fuel and wholesale electricity pricing risks, which could result in unanticipated liabilities or increased volatility in earnings.
The business and operations of PNMR and its operating subsidiaries are subject to changes in purchased power prices and fuel costs that may cause increases in the amounts that must be paid for power supplies on the wholesale market and the cost of producing power in owned generation plants. As evidenced by the California energy crisis in 2000-2001, prices for electricity, fuel and natural gas may fluctuate substantially over relatively short periods of time and expose PNMR and its operating subsidiaries to significant commodity price risks.
Among the factors that could affect market prices for electricity and fuel are:
prevailing market prices for coal, oil, natural gas and other fuels used in PNM's generation plants, including associated transportation costs, and supplies of such commodities,
changes in the regulatory framework for the commodities markets that PNMR and its operating subsidiaries rely on for purchased power and fuel,
liquidity in the general wholesale electricity market,
the actions of external parties; such as the FERC or independent system operators, that may impose price limitations and other mechanisms to address some of the volatility in the United States' Western energy markets,
weather conditions impacting demand for electricity or availability of hydroelectric power or fuel supplies,
the rate of growth in electricity as a result of population changes, regional economic conditions and the implementation of conservation programs,
union and labor relations,
natural disasters, wars, embargoes and other catastrophic events, and
changes in federal and state energy and environmental laws and regulations.
PNMR and its operating subsidiaries rely on derivatives such as forward contracts, futures contracts, options and swaps to manage these risks. They attempt to manage their exposure from these activities through enforcement of established risk limits and risk management procedures. PNMR and its operating subsidiaries cannot be certain that these strategies will be successful in managing pricing risk, or that they will not result in net liabilities as a result of future volatility in these markets.
In addition, although PNMR and its operating subsidiaries routinely enter into contracts to offset positions (i.e. to hedge its exposure to the risks of demand, market effects of weather and changes in commodity prices), they do not always hedge the entire exposure of their operations from commodity price volatility. Furthermore, their ability to hedge exposure to commodity price volatility depends on liquid commodity markets. To the extent the commodity markets are illiquid, they may not be able to execute their risk management strategies, which could result in greater open positions than they would prefer at a given time. To the extent that open positions exist, fluctuating commodity prices can improve or diminish the business, financial position, results of operations and liquidity of PNMR and its operating subsidiaries.
Impairments of PNMR's, PNM's and TNMP's tangible long-lived assets could adversely affect their business, financial position, liquidity and results of operations.
PNMR, PNM and TNMP evaluate their tangible long-lived assets for impairment whenever indicators of impairment exist pursuant to SFAS 144. These potential impairment triggers would include fluctuating market conditions as a result of industry deregulation; planned and scheduled customer purchase commitments; future market penetration; fluctuating market prices resulting from factors including changing fuel costs and other economic conditions; weather patterns; and other market trends. Accounting rules require that if the sum of the undiscounted expected future cash flows from a company's asset (excluding interest charges that will be recognized as expenses when incurred) is less than the carrying value of the asset, then asset impairment must be recognized in the financial statements. The amount of impairment recognized is the difference between the fair value of the asset and the carrying value of the asset. PNMR, PNM and TNMP determined that no triggering events occurred during the period for their tangible long-lived assets.
PNM has three turbines, which are currently in storage, with a combined carrying value of approximately $79.7 million. PNM believes that it will be able to place two of the turbines in service and recover the costs of these two turbines in rates. In July 2005, PNM filed with the
163
NMPRC an application for a CCN in which PNM requested NMPRC approval to include in PNM's retail rate base in its next retail electric rate case the costs associated with the conversion of the Afton generating station from a combustion turbine to a combined cycle unit utilizing one of the turbines in storage. The conversion to a combined-cycle unit, as proposed, would utilize a turbine currently in storage with a book value of $24.3 million. As part of the negotiations regarding regulatory treatment of the Afton facility, the parties also are discussing alternative equipment configurations under which the turbine in storage would not be used. If such an alternative configuration were to be agreed upon, the Company would evaluate other alternatives, including selling the unit, which could result in a write-down depending on prevailing market conditions for this type of equipment. The Company is unable to predict the outcome of the Afton CCN case.
PNMR and PNM analyzed the remaining turbine for impairment and concluded no impairment existed based on their plans for its use. The carrying amount of this turbine at September 30, 2005 was $16.6 million. PNMR and PNM expect to begin construction utilizing this turbine over the next several years. If PNMR and PNM were unable to realize these plans, PNMR and PNM would be forced to recognize a loss with respect to the carrying value of the turbine depending on prevailing market conditions. PNMR and PNM will continue to analyze the turbine for impairment in accordance with SFAS 144.
Impairments of goodwill and intangible assets of PNMR and its subsidiaries could adversely affect their business, financial position, liquidity and results of operations.
PNMR recorded $492.7 million of goodwill as a result of its acquisition of TNP. As required by SFAS 142, PNMR evaluates goodwill for impairment annually and between annual tests whenever indicators of impairment exist pursuant to SFAS 142. Impairment of goodwill exists when the carrying amount of goodwill exceeds its implied fair value. The implied value of goodwill shall be determined in the same manner as the amount of goodwill recognized in a business combination is determined.
PNMR also recorded $63.1 million of other intangible assets as a result of its acquisition of TNP. Of the $63.1 million of acquired intangible assets, $53.2 million was assigned to the trade name "First Choice". The trade name has an indefinite useful life and therefore, no amortization will be recognized until its useful life is determined to be no longer indefinite. PNMR will evaluate the remaining useful life of the First Choice trade name each reporting period as required by SFAS 142 to determine whether events or circumstances continue to support an indefinite useful life.
The remaining $ 9.9 million of acquired intangible assets was assigned to the First Choice customer list. The useful life of the customer list is estimated to be eight years and will be amortized on a straight-line basis over eight years. PNMR will evaluate the remaining useful life of the First Choice customer list each reporting period as required by SFAS 144 to determine whether events or circumstances continue to support the remaining amortization period.
Actual results could differ from estimates used to prepare PNMR's, PNM's and TNMP's financial statements.
In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues,
164
expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. For more information about these estimates and assumptions, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies."
Provisions of PNMR's organizational documents, as well as several other statutory and regulatory factors, will limit another party's ability to acquire PNMR and could deprive PNMR's shareholders of the opportunity to gain a takeover premium for shares of PNMR's common stock.
PNMR's restated articles of incorporation and by-laws include a number of provisions that may have the effect of discouraging persons from acquiring large blocks of PNMR's common stock or delaying or preventing a change in control of PNMR. The material provisions that may have such an effect include:
authorization for the PNMR Board to issue PNMR's preferred stock in series and to fix rights and preferences of the series (including, among other things, whether, and to what extent, the shares of any series will have voting rights, subject to certain limitations, and the extent of the preferences of the shares of any series with respect to dividends and other matters),
provisions classifying PNMR's Board into three classes, with the directors being elected for staggered terms,
advance notice procedures with respect to any proposal other than those adopted or recommended by PNMR's Board, and
165
provisions specifying that only a majority of the Board, the chairman of the Board, the president or holders of not less than one-tenth of all of PNMR's shares entitled to vote may call a special meeting of stockholders.
Under the New Mexico Public Utility Act, NMPRC approval is required for certain transactions that may result in PNMR's change in control or exercise of control. Certain acquisitions of PNMR's outstanding voting securities would also require FERC approval under the FERC's authority resulting from the Energy Policy Act and the repeal of PUHCA. See Note 9 - "Regulatory and Rate Matters - Energy Policy Act" in the Notes to Consolidated Financial Statements for further discussion.
166
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
See "Quantitative and Qualitative Disclosure About Market Risk" in "Item 2. Management 's Discussion and Analysis of Financial Condition and Results of Operations".
Disclosure Controls and Procedures
PNMR, PNM and TNMP each maintain disclosure controls and procedures designed to ensure that it is able to collect the information it is required to disclose in the reports it files with the SEC, and to process, summarize and disclose this information within the time periods specified in the rules of the SEC. Based on an evaluation of each of the registrants' disclosure controls and procedures as of the end of the period covered by this report conducted by the registrants' management, with the participation of the Chief Executive and Chief Financial Officers, the Chief Executive and Chief Financial Officers believe that these controls and procedures are effective to ensure that each of the registrants is able to collect, process, and disclose the information it is required to disclose in the reports it files with the SEC within the required time periods.
Changes in Internal Controls
There have been no changes in the Company's internal controls over financial reporting for the quarter ended September 30, 2005, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.
The Company is currently undergoing a diligent effort to ensure TNP's compliance with Section 404 of the Sarbanes-Oxley Act of 2002. As integration activities occur, the Company will continue to integrate the Company's internal controls into TNP's operations. It is expected that this effort will continue during the remainder of 2005 and into 2006.
PART II - OTHER INFORMATION
See Note 8 - "Commitments and Contingencies," in the Notes to Consolidated Financial Statements for information related to the following matters, incorporated in this item by reference.
SESCO Matter (for both PNM and TNMP)
Legal Proceedings discussed under the captions "Western United States Wholesale Power Market" and "FERC Rule Making"
See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Acquisition" for information related to the SW Acquisition litigation, incorporated in this item by reference.
ITEM 5. OTHER EVENTS
On August 8, 2005, Mr. John Loyack, Senior Vice President and Chief Financial Officer of PNMR, resigned from that position to pursue other interests. Mr. Loyack did not resign as a result of any disagreement with the operations, policies or practices of PNMR. He continued as Chief Financial Officer through August 9, 2005, and continued as a Senior Vice President of the Company until September 1, 2005.
Pending a national search for a permanent Chief Financial Officer, the Board appointed Mr. Terry Horn to be the acting Chief Financial Officer of PNMR effective August 10, 2005, acting Chief Financial Officer of PNM effective September 12, 2005 and acting Chief Financial Officer of TNP and TNMP effective September 13, 2005. Mr. Horn was Vice President and Treasurer of PNM and PNMR since 1998 and 2001, respectively, and he became Corporate Secretary of PNMR in May 2005. Mr. Horn's title pending appointment of a permanent Chief Financial Officer is Vice President, Corporate Secretary and Acting Chief Financial Officer.
4.10
Purchase Contract Agreement, dated as of October 7, 2005, between PNMR and U.S. Bank National Association, as purchase contract agent
4.11
Indenture, dated as of October 7, 2005, between PNMR and U.S. Bank National Association, as trustee
4.12
Supplemental Indenture, dated as of October 7, 2005, between PNMR and U.S. Bank National Association, as trustee
10.3
Joinder Agreement, dated as of September 30, 2005, between TNMP, as applicant borrower and Bank of America, as administrative agent
10.4
Third Supplement to Unit Purchase Agreement dated August 12, 2005 between PNMR and Cascade Investment, LLC
10.5
Fourth Supplement to Unit Purchase Agreement dated September 30, 2005 between PNMR and Cascade Investment, LLC
10.30**
PNM Resources, Inc. 2005 Officer Incentive Plan Amended (August 2, 2005)
10.31**
Summary of Executive Paid Time Off Policy Effective January 1, 2006
12.2
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
31.1
PNMR/PNM
Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.3
31.4
32.1
Chief Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.3
32.4
99.1
Remarketing Agreement, dated as of October 7, 2005, among Banc of America Securities LLC, as remarketing agent, PNMR and U.S. Bank National Association, as purchase contract agent
99.2
Pledge Agreement, dated as of October 7, 2005, between PNMR and U.S. Bank National Association
99.3
Registration Rights Agreement, dated as of October 7, 2005, between PNMR and Cascade Investment, LLC
** designates each management contract or compensatory plan or arrangement required to be identified.
170
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.
(Registrants)
Date: November 3, 2005
/s/ Thomas G. Sategna
Thomas G. Sategna
Vice President and Corporate Controller
(Officer duly authorized to sign this report)