þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Delaware | 35-2108964 | |
(State or other jurisdiction of
incorporation or organization) |
(I.R.S. Employer
Identification No.) |
|
801 East 86th Avenue | ||
Merrillville, Indiana | 46410 | |
(Address of principal executive offices) | (Zip Code) |
Large accelerated filer þ | Accelerated filer o |
Non-accelerated filer
o
(Do not check if smaller reporting company) |
Smaller Reporting Company o |
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EX-101 INSTANCE DOCUMENT | ||||||||
EX-101 SCHEMA DOCUMENT | ||||||||
EX-101 CALCULATION LINKBASE DOCUMENT | ||||||||
EX-101 LABELS LINKBASE DOCUMENT | ||||||||
EX-101 PRESENTATION LINKBASE DOCUMENT | ||||||||
EX-101 DEFINITION LINKBASE DOCUMENT |
2
NiSource Subsidiaries and Affiliates
|
||
Capital Markets
|
NiSource Capital Markets, Inc. | |
CER
|
Columbia Energy Resources, Inc. | |
CGORC
|
Columbia Gas of Ohio Receivables Corporation | |
CNR
|
Columbia Natural Resources, Inc. | |
Columbia
|
Columbia Energy Group | |
Columbia Gulf
|
Columbia Gulf Transmission Company | |
Columbia of Kentucky
|
Columbia Gas of Kentucky, Inc. | |
Columbia of Maryland
|
Columbia Gas of Maryland, Inc. | |
Columbia of Massachusetts
|
Bay State Gas Company | |
Columbia of Ohio
|
Columbia Gas of Ohio, Inc. | |
Columbia of Pennsylvania
|
Columbia Gas of Pennsylvania, Inc. | |
Columbia of Virginia
|
Columbia Gas of Virginia, Inc. | |
Columbia Transmission
|
Columbia Gas Transmission, L.L.C. | |
CPRC
|
Columbia Gas of Pennsylvania Receivables Corporation | |
Crossroads Pipeline
|
Crossroads Pipeline Company | |
Granite State Gas
|
Granite State Gas Transmission, Inc. | |
Hardy Storage
|
Hardy Storage Company, L.L.C. | |
Kokomo Gas
|
Kokomo Gas and Fuel Company | |
Millennium
|
Millennium Pipeline Company, L.L.C. | |
NARC
|
NIPSCO Accounts Receivable Corporation | |
NDC Douglas Properties
|
NDC Douglas Properties, Inc. | |
NiSource
|
NiSource Inc. | |
NiSource Corporate Services
|
NiSource Corporate Services Company | |
NiSource Development Company
|
NiSource Development Company, Inc. | |
NiSource Finance
|
NiSource Finance Corp. | |
Northern Indiana
|
Northern Indiana Public Service Company | |
Northern Indiana Fuel and Light
|
Northern Indiana Fuel and Light Company | |
Northern Utilities
|
Northern Utilities, Inc. | |
PEI
|
PEI Holdings, Inc. | |
Whiting Clean Energy
|
Whiting Clean Energy, Inc. | |
|
||
Abbreviations
|
||
ACES
|
American Clean Energy and Security Act of 2009 | |
AFUDC
|
Allowance for funds used during construction | |
Ameren
|
Ameren Services Company | |
AMRP
|
Accelerated Main Replacement Program | |
AOC
|
Administrative Order by Consent | |
AOCI
|
Accumulated other comprehensive income | |
ARRs
|
Auction Revenue Rights | |
ASC
|
Accounting Standards Codification | |
BBA
|
British Banker Association | |
Bcf
|
Billion cubic feet | |
Board
|
Board of Directors | |
BPAE
|
BP Alternative Energy North America Inc | |
BTMU
|
The Bank of Tokyo-Mitsubishi UFJ, LTD. | |
BTU
|
British Thermal Unit | |
CAA
|
Clean Air Act | |
CAIR
|
Clean Air Interstate Rule | |
CAMR
|
Clean Air Mercury Rule | |
CARE
|
Conservation and Ratemaking Efficiency | |
CCGT
|
Combined Cycle Gas Turbine | |
CERCLA
|
Comprehensive Environmental Response Compensation and Liability Act (also known as Superfund) | |
Chesapeake
|
Chesapeake Appalachia, L.L.C. | |
CSAPR
|
Cross-State Air Pollution Rule |
3
Day 2
|
Began April 1, 2005 and refers to the operational control of the energy markets by MISO, including the dispatching of wholesale electricity and generation, managing transmission constraints, and managing the day-ahead, real-time and financial transmission rights markets | |
DPU
|
Department of Public Utilities | |
DSM
|
Demand Side Management | |
Dth
|
Dekatherm | |
ECRM
|
Environmental Cost Recovery Mechanism | |
ECT
|
Environmental Cost Tracker | |
EERM
|
Environmental Expense Recovery Mechanism | |
EPA
|
United States Environmental Protection Agency | |
EPS
|
Earnings per share | |
FAC
|
Fuel adjustment clause | |
FASB
|
Financial Accounting Standards Board | |
FERC
|
Federal Energy Regulatory Commission | |
FTRs
|
Financial Transmission Rights | |
GAAP
|
U.S. Generally Accepted Accounting Principles | |
GCR
|
Gas cost recovery | |
GHG
|
Greenhouse gases | |
gwh
|
Gigawatt hours | |
IDEM
|
Indiana Department of Environmental Management | |
IFRS
|
International Financial Reporting Standards | |
IRP
|
Infrastructure Replacement Program | |
IURC
|
Indiana Utility Regulatory Commission | |
LDCs
|
Local distribution companies | |
LIBOR
|
London InterBank Offered Rate | |
LIFO
|
Last in first out | |
Mcf
|
Million cubic feet | |
MISO
|
Midwest Independent Transmission System Operator | |
Mitchell
|
Dean H. Mitchell Coal Fired Generating Station | |
MMDth
|
Million dekatherms | |
mw
|
Megawatts | |
NAAQS
|
National Ambient Air Quality Standards | |
NOV
|
Notice of Violation | |
NO2
|
Nitrogen dioxide | |
NOx
|
Nitrogen oxide | |
NSR
|
New Source Review | |
NYMEX
|
New York Mercantile Exchange | |
OCI
|
Other Comprehensive Income (Loss) | |
OPEB
|
Other Postretirement and Postemployment Benefits | |
OUCC
|
Indiana Office of Utility Consumer Counselor | |
PADEP
|
Pennsylvania Department of Environmental Protection | |
Piedmont
|
Piedmont Natural Gas Company, Inc. | |
PIPP
|
Percentage of Income Plan | |
PJM
|
PJM Interconnection is a regional transmission organization (RTO) that coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia. | |
PM
|
particulate matter | |
PSC
|
Public Service Commission | |
PUC
|
Public Utility Commission | |
PUCO
|
Public Utilities Commission of Ohio | |
RBS
|
Royal Bank of Scotland PLC | |
RCRA
|
Resource Conservation and Recovery Act | |
RSG
|
Revenue Sufficiency Guarantee | |
RTO
|
Regional Transmission Organization | |
SEC
|
Securities and Exchange Commission | |
SIP
|
State Implementation Plan | |
SO2
|
Sulfur dioxide |
4
VaR
|
Value-at-risk and instrument sensitivity to market factors | |
VIE
|
Variable Interest Entities | |
VSCC
|
Virginia State Corporation Commission |
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
Three Months Ended
Six Months Ended
June 30,
June 30,
(in millions, except per share amounts)
2011
2010
2011
2010
$
500.4
$
454.3
$
1,872.4
$
1,795.4
307.3
264.3
710.3
634.8
349.2
340.5
696.3
658.4
71.4
112.0
181.5
441.2
1,228.3
1,171.1
3,460.5
3,529.8
462.5
439.1
1,633.4
1,725.4
765.8
732.0
1,827.1
1,804.4
402.5
377.1
835.0
816.7
134.5
151.6
273.4
301.4
0.7
0.1
67.8
64.5
160.8
151.4
604.8
593.2
1,269.9
1,269.6
2.3
0.4
5.3
7.8
163.3
139.2
562.5
542.6
(94.4
)
(98.4
)
(184.2
)
(197.2
)
0.6
2.6
3.9
5.2
(93.8
)
(95.8
)
(180.3
)
(192.0
)
69.5
43.4
382.2
350.6
30.0
15.4
137.9
125.2
39.5
28.0
244.3
225.4
(0.6
)
0.1
(0.2
)
(0.1
)
0.1
$
38.9
$
28.1
$
244.1
$
225.4
$
0.14
$
0.10
$
0.87
$
0.81
$
0.14
$
0.10
$
0.87
$
0.81
$
0.14
$
0.10
$
0.85
$
0.81
$
0.14
$
0.10
$
0.85
$
0.81
$
0.23
$
0.23
$
0.69
$
0.69
280.2
277.6
279.8
277.3
287.1
278.4
286.2
278.0
Table of Contents
June 30,
December 31,
(in millions)
2011
2010
$
19,783.8
$
19,494.9
(8,602.9
)
(8,492.6
)
11,180.9
11,002.3
114.1
94.7
11,295.0
11,097.0
2.3
7.9
197.2
200.9
150.8
139.7
350.3
348.5
59.9
9.2
154.6
202.9
638.3
1,079.3
1.2
99.0
278.0
298.2
24.7
135.7
87.0
83.8
44.9
46.0
116.0
159.5
118.2
62.7
121.9
151.8
100.4
120.8
1,745.1
2,448.9
190.6
240.3
1,622.2
1,650.4
3,677.3
3,677.3
303.1
308.6
42.0
35.1
120.7
132.7
5,955.9
6,044.4
$
19,346.3
$
19,938.8
Table of Contents
Condensed Consolidated Balance Sheets (unaudited) (continued)
June 30,
December 31,
(in millions, except share amounts)
2011
2010
$
2.8
$
2.8
4,132.9
4,103.9
952.6
901.8
(54.5
)
(57.9
)
(30.4
)
(27.4
)
5,003.4
4,923.2
6,340.0
5,936.1
11,343.4
10,859.3
30.0
34.2
870.4
1,382.5
316.2
581.8
64.6
0.1
183.1
318.1
179.5
221.1
114.4
114.4
121.4
11.8
135.0
173.9
155.4
266.1
5.0
6.8
83.5
92.9
23.3
23.3
0.3
46.0
86.0
230.0
336.4
2,558.1
3,649.4
127.8
181.6
2,369.1
2,209.7
31.3
33.7
75.5
68.6
0.3
919.6
1,039.6
1,624.8
1,595.8
138.9
138.8
157.8
162.0
5,444.8
5,430.1
$
19,346.3
$
19,938.8
Table of Contents
Six Months Ended June 30,
(in millions)
2011
2010
$
244.1
$
225.4
273.4
301.4
15.3
4.4
132.1
38.6
(2.6
)
(17.2
)
17.2
6.0
0.1
0.7
(4.4
)
(7.8
)
(0.1
)
0.2
0.1
4.2
5.4
(1.9
)
(3.7
)
9.9
7.9
434.6
245.1
97.8
24.8
13.7
147.6
(250.4
)
(235.4
)
(134.9
)
(104.7
)
(40.7
)
6.2
5.3
220.7
(252.3
)
(166.2
)
(51.3
)
(26.3
)
(30.5
)
20.6
28.1
28.3
98.3
(118.9
)
1.7
6.3
(3.6
)
12.1
4.6
(4.8
)
2.9
780.1
447.3
(44.1
)
(44.8
)
736.0
402.5
(445.0
)
(336.9
)
0.5
9.4
0.3
48.3
(38.0
)
(0.1
)
(0.3
)
(36.0
)
(19.9
)
(423.4
)
(394.3
)
0.4
(423.4
)
(393.9
)
395.3
(13.0
)
(5.2
)
(8.2
)
(512.2
)
109.8
7.9
6.8
(3.0
)
(1.4
)
(128.7
)
(127.6
)
(261.9
)
(17.6
)
94.8
35.4
(44.1
)
(44.4
)
9.2
16.4
$
59.9
$
7.4
Table of Contents
Three Months Ended
Six Months Ended
June 30,
June 30,
(in millions, net of taxes)
2011
2010
2011
2010
$
38.9
$
28.1
$
244.1
$
225.4
1.1
(0.1
)
0.9
0.4
0.6
(10.4
)
1.7
(13.3
)
0.4
0.5
0.8
(1.6
)
2.1
(10.0
)
3.4
(14.5
)
$
41.0
$
18.1
$
247.5
$
210.9
(a)
Net unrealized gains (losses) on available-for-sale securities, net of $0.7 million tax expense and $0.2 million tax benefit in the second quarter of 2011
and 2010, respectively, and $0.5 million and $0.1 million tax expense for the first six months of 2011 and 2010, respectively.
(b)
Net unrealized gains (losses) on derivatives qualifying as cash flow hedges, net of $0.4 million tax expense and $6.6 million tax benefit in the second
quarter of 2011 and 2010, respectively, and $1.1 million tax expense and $8.4 million tax benefit for the first six months of 2011 and 2010, respectively.
(c)
Net unrealized gains (losses) on cash flow hedges includes gains of $0.2 million and losses of $11.2 million related to the unrealized gains and losses of
interest swaps held by NiSources unconsolidated equity method investments for the three months ended June 30, 2011 and 2010, respectively. Net unrealized
gains (losses) on cash flow hedges include gains of $0.4 million and losses of $14.3 million related to the unrealized gains and losses of interest swaps
held by NiSources unconsolidated equity method investments for the six months ended June 30, 2011 and 2010, respectively.
(d)
Unrecognized pension benefit and OPEB costs, net of $0.3 million tax expense in the second quarter of 2011 and 2010, and $0.7 million tax expense and $1.1
million tax benefit for the first six months of 2011 and 2010, respectively.
Table of Contents
Table of Contents
Three Months Ended
Six Months Ended
June 30,
June 30,
(in thousands)
2011
2010
2011
2010
280,217
277,566
279,780
277,258
1,078
300
1,061
300
342
511
326
480
5,422
4,989
287,059
278,377
286,156
278,038
Table of Contents
Property, plant and
Assets of discontinued operations and held for sale:
equipment, net
Other assets
Total
$
2.3
$
$
2.3
$
2.3
$
$
2.3
Property, plant and
Assets of discontinued operations and held for sale:
equipment, net
Other assets
Total
$
5.6
$
$
5.6
2.3
2.3
$
7.9
$
$
7.9
Table of Contents
Three Months Ended
Six Months Ended
June 30,
June 30,
(in millions)
2011
2010
2011
2010
$
$
$
$
0.7
(0.8
)
0.2
(0.2
)
(0.1
)
(0.2
)
0.1
$
(0.6
)
$
0.1
$
(0.2
)
$
(0.1
)
$
$
$
$
0.1
(in millions)
2011
2010
$
138.8
$
138.2
0.3
0.4
3.8
3.7
(1.1
)
(5.5
)
(2.9
)
$
138.9
$
136.8
Table of Contents
Table of Contents
Table of Contents
Table of Contents
Table of Contents
Table of Contents
Table of Contents
Table of Contents
Table of Contents
June 30, 2011
December 31, 2010
31.0
28.4
1.0
1.6
0.3
0.4
4.9
2.0
35.0
48.2
34.9
48.0
15,972.0
8,279.1
(a)
Basis contract volumes not included in the above table were 30.3 MMDth and 42.0 MMDth as of June 30, 2011 and December 31,
2010, respectively.
(b)
Basis contract volumes not included in the above table were 36.8 MMDth and 52.1 MMDth as of June 30, 2011 and December 31, 2010,
respectively.
Table of Contents
Table of Contents
June 30,
December 31,
Asset Derivatives
(in millions)
2011
2010
Fair Value
Fair Value
$
$
60.7
61.1
$
60.7
$
61.1
$
116.0
$
159.5
129.9
179.2
$
245.9
$
338.7
$
306.6
$
399.8
June 30,
December 31,
Liability Derivatives
(in millions)
2011
2010
Fair Value
Fair Value
$
0.5
$
1.0
0.1
0.2
$
0.6
$
1.2
$
134.5
$
172.9
127.7
181.4
$
262.2
$
354.3
$
262.8
$
355.5
Amount of Gain (Loss)
Amount of Gain (Loss)
Recognized in OCI on
Reclassified from AOCI
Derivative (Effective
Location of Gain (Loss)
into Income (Effective
Portion)
Reclassified from AOCI
Portion)
Derivatives in Cash Flow
June 30,
June 30,
into Income (Effective
June 30,
June 30,
Hedging Relationships
2011
2010
Portion)
2011
2010
$
$
0.4
Cost of Sales
$
0.2
$
0.3
0.4
0.4
Interest expense, net
(0.7
)
(0.7
)
$
0.4
$
0.8
$
(0.5
)
$
(0.4
)
Table of Contents
Amount of Gain (Loss)
Amount of Gain (Loss)
Recognized in OCI on
Reclassified from AOCI
Derivative (Effective
Location of Gain (Loss)
into Income (Effective
Portion)
Reclassified from AOCI
Portion)
Derivatives in Cash Flow
June 30,
June 30,
into Income (Effective
June 30,
June 30,
Hedging Relationships
2011
2010
Portion)
2011
2010
$
0.5
$
0.2
Cost of Sales
$
0.8
$
0.8
0.8
0.8
Interest expense, net
(1.3
)
(1.3
)
$
1.3
$
1.0
$
(0.5
)
$
(0.5
)
Amount of Gain (Loss) Recognized
Location of Gain (Loss)
in Income on Derivative
Recognized in Income on
(Ineffective Portion and Amount
Derivative (Ineffective Portion
Excluded from Effectiveness
and Amount Excluded from
Testing)
Effectiveness Testing)
June 30, 2011
June 30, 2010
Cost of Sales
$
$
Interest expense, net
$
$
Amount of Gain (Loss) Recognized
Location of Gain (Loss)
in Income on Derivative
Recognized in Income on
(Ineffective Portion and Amount
Derivative (Ineffective Portion
Excluded from Effectiveness
and Amount Excluded from
Testing)
Effectiveness Testing)
June 30, 2011
June 30, 2010
Cost of Sales
$
$
Interest expense, net
$
$
Amount of (Loss) Gain Recognized
Location of (Loss) Gain Recognized in
in Income on Derivatives
Income on Derivatives
June 30, 2011
June 30, 2010
Interest expense, net
$
9.8
$
4.0
$
9.8
$
4.0
Table of Contents
Amount of Gain (Loss) Recognized
Location of Gain (Loss) Recognized in
in Income on Derivatives
Income on Derivatives
June 30, 2011
June 30, 2010
Interest expense, net
$
(0.4
)
$
6.1
$
(0.4
)
$
6.1
Amount of Gain (Loss) Recognized
Location of Gain (Loss) Recognized in
in Income on Related Hedged Items
Income on Related Hedged Item
June 30, 2011
June 30, 2010
Interest expense, net
$
(9.8
)
$
(4.0
)
$
(9.8
)
$
(4.0
)
Amount of Gain (Loss) Recognized
Location of Gain (Loss) Recognized in
in Income on Related Hedged Items
Income on Related Hedged Item
June 30, 2011
June 30, 2010
Interest expense, net
$
0.4
$
(6.1
)
$
0.4
$
(6.1
)
Amount of Realized/Unrealized Gain
Location of Gain (Loss)
(Loss) Recognized in Income on
Recognized in
Derivatives *
Income on Derivatives
June 30, 2011
June 30, 2010
Gas Distribution revenues
$
(0.1
)
$
4.2
Other revenues
7.8
(4.5
)
Cost of Sales
(4.5
)
(1.0
)
$
3.2
$
(1.3
)
*
For the amounts of realized/unrealized gain (loss) recognized in income on derivatives disclosed
in the table above, gains of $3.4 million and $4.4 million for the second quarter of 2011 and 2010,
respectively, were deferred as allowed by regulatory orders. These amounts will be amortized to
income over future periods of up to twelve months as specified in a regulatory order.
Table of Contents
Amount of Realized/Unrealized Gain
Location of Gain (Loss)
(Loss) Recognized in Income on
Derivatives Not Designated as Hedging
Recognized in
Derivatives *
Instruments
Income on Derivatives
June 30, 2011
June 30, 2010
Gas Distribution revenues
$
(21.8
)
$
(16.8
)
Other revenues
18.4
72.7
Cost of Sales
(7.8
)
(72.2
)
$
(11.2
)
$
(16.3
)
*
For the amounts of realized/unrealized gain (loss) recognized in income on derivatives disclosed
in the table above, losses of $19.3 million and $16.2 million for the six months of 2011 and 2010,
respectively, were deferred as allowed per regulatory orders. These amounts will be amortized to
income over future periods of up to twelve months as specified in a regulatory order.
Table of Contents
Quoted Prices in
Significant
Active Markets
Other
Significant
for Identical
Observable
Unobservable
Assets
Inputs
Inputs
Balance as of
(Level 1)
(Level 2)
(Level 3)
June 30, 2011
$
$
122.3
$
$
122.3
121.1
2.5
123.6
60.7
60.7
38.8
42.4
81.2
$
159.9
$
227.9
$
$
387.8
$
$
2.8
$
$
2.8
257.1
2.1
0.8
260.0
$
257.1
$
4.9
$
0.8
$
262.8
Quoted Prices in
Significant
Active Markets
Other
Significant
for Identical
Observable
Unobservable
Assets
Inputs
Inputs
Balance as of
(Level 1)
(Level 2)
(Level 3)
December 31, 2010
$
$
161.4
$
$
161.4
173.8
3.2
0.3
177.3
61.1
61.1
43.5
37.9
81.4
$
217.3
$
263.6
$
0.3
$
481.2
$
$
3.6
$
$
3.6
348.5
3.3
0.1
351.9
$
348.5
$
6.9
$
0.1
$
355.5
Table of Contents
Amortized
Total
Total
Fair
(in millions)
Cost
Gains
Losses
Value
$
38.4
$
0.6
$
(0.2
)
$
38.8
41.2
1.3
(0.1
)
42.4
$
79.6
$
1.9
$
(0.3
)
$
81.2
Amortized
Total
Total
Fair
(in millions)
Cost
Gains
Losses
Value
$
43.4
$
0.6
$
(0.5
)
$
43.5
36.1
2.0
(0.2
)
37.9
$
79.5
$
2.6
$
(0.7
)
$
81.4
Table of Contents
Financial
Transmission
Other
Three Months Ended June 30, 2011
(in millions)
Rights
Derivatives
Total
$
$
(0.1
)
$
(0.1
)
(0.6
)
(0.6
)
(0.5
)
(0.5
)
0.4
0.4
$
$
(0.8
)
$
(0.8
)
$
$
(1.5
)
$
(1.5
)
Financial
Transmission
Other
Three Months Ended June 30, 2010
(in millions)
Rights
Derivatives
Total
$
0.9
$
(0.1
)
$
0.8
(3.2
)
(3.2
)
2.3
0.3
2.6
$
$
0.2
$
0.2
$
$
$
Table of Contents
Financial
Transmission
Other
Six Months Ended, June 30, 2011
(in millions)
Rights
Derivatives
Total
$
$
0.2
$
0.2
(1.0
)
(1.0
)
(1.0
)
(1.0
)
1.0
1.0
$
$
(0.8
)
$
(0.8
)
$
$
(1.5
)
$
(1.5
)
Financial
Transmission
Other
Six Months Ended, June 30, 2010
(in millions)
Rights
Derivatives
Total
$
1.9
$
0.2
$
2.1
(4.2
)
(4.2
)
2.3
2.3
$
$
0.2
$
0.2
$
$
$
Table of Contents
Carrying
Estimated Fair
Carrying
Estimated Fair
Amount as of
Value as of
Amount as of
Value as of
(in millions)
June 30, 2011
June 30, 2011
Dec. 31, 2010
Dec. 31, 2010
$
27.6
$
26.4
$
26.7
$
25.4
6,370.0
6,972.5
5,970.3
6,482.4
Table of Contents
Table of Contents
Table of Contents
Other Postretirement
Pension Benefits
Benefits
Three Months Ended June 30,
(in millions)
2011
2010
2011
2010
$
9.4
$
9.8
$
2.5
$
2.4
29.9
31.4
9.6
10.9
(41.8
)
(35.9
)
(6.7
)
(5.8
)
0.3
0.3
0.1
0.5
(0.1
)
0.8
13.9
14.5
1.7
1.5
$
11.5
$
20.3
$
7.3
$
10.1
Other Postretirement
Pension Benefits
Benefits
Six Months Ended June 30,
(in millions)
2011
2010
2011
2010
$
18.8
$
19.5
$
5.0
$
4.8
59.8
62.8
19.2
21.3
(83.6
)
(71.8
)
(13.4
)
(11.7
)
0.6
0.6
0.2
1.0
(0.2
)
0.7
27.8
29.0
3.4
3.0
$
23.0
$
40.5
$
14.6
$
18.7
Table of Contents
Table of Contents
June 30,
December 31,
(in millions)
2011
2010
$
180.5
$
506.0
1,107.5
183.9
275.0
$
870.4
$
1,382.5
Table of Contents
Table of Contents
(in millions)
Total
2011
2012
2013
2014
2015
After
$
5,830.9
$
$
315.0
$
545.0
$
500.0
$
230.0
$
4,240.9
153.1
51.7
19.5
80.0
1.9
183.9
183.9
686.5
686.5
38.0
12.2
24.6
0.2
1.0
321.8
2.0
12.3
222.8
32.2
52.5
$
7,214.2
$
936.3
$
371.4
$
768.0
$
533.2
$
310.0
$
4,295.3
Table of Contents
Table of Contents
Table of Contents
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Table of Contents
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
(in millions)
June 30, 2011
December 31, 2010
$
7.5
$
6.1
(2.9
)
(2.4
)
(53.6
)
(56.4
)
20.5
21.6
(41.8
)
(43.3
)
15.8
16.5
$
(54.5
)
$
(57.9
)
Table of Contents
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Three Months Ended
Six Months Ended
June 30,
June 30,
(in millions)
2011
2010
2011
2010
$
629.7
$
552.0
$
2,214.5
$
2,097.4
0.2
2.7
0.9
8.5
629.9
554.7
2,215.4
2,105.9
200.5
185.6
413.9
380.1
33.0
31.7
75.0
93.8
233.5
217.3
488.9
473.9
350.8
342.3
699.6
662.1
0.2
0.2
0.4
0.4
351.0
342.5
700.0
662.5
47.3
91.2
132.5
390.2
122.2
103.1
232.7
209.9
169.5
194.3
365.2
600.1
(155.6
)
(137.7
)
(309.0
)
(312.6
)
$
1,228.3
$
1,171.1
$
3,460.5
$
3,529.8
$
46.4
$
18.5
$
288.0
$
253.6
84.7
74.9
203.2
200.8
39.8
49.6
83.0
94.7
(7.6
)
(3.8
)
(11.7
)
(6.5
)
$
163.3
$
139.2
$
562.5
$
542.6
Table of Contents
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Six Months Ended June 30,
(in millions)
2011
2010
$
65.1
$
63.7
(23.5
)
10.8
10.1
$
180.0
$
186.6
4.7
49.9
Table of Contents
Electric Operations net revenues increased $15.1 million primarily due to increased
industrial usage and margins resulting from improved economic conditions.
Gas Transmission and Storage Operations net revenues increased $15.0 million primarily
due to higher demand margin revenues as a result of growth projects placed into service in
the second half of the prior year.
Table of Contents
Depreciation and amortization decreased $28.0 million primarily due to new approved
rates at Northern Indianas Gas Distribution operations.
NiSource incurred lower interest expense of $13.0 million primarily due to the $681.8
million November 2010 long-term debt maturity and the December 2010 tender offer repurchase
of long-term debt of $273.1 million.
Operation and maintenance expenses, excluding the decrease in trackers of $23.9 million,
increased $42.2 million as a result of higher employee and administrative expenses and
electric generation costs.
On July 18, 2011, Northern Indiana filed a broad-based settlement agreement which, if
approved by the IURC, would resolve the companys November 2010 electric base rate case.
The settlement provides Northern Indiana with the foundation to make ongoing investments in
Northern Indianas energy infrastructure to help fuel job creation and economic growth and
to earn a reasonable return on its investment for shareholders on a sustainable basis.
On July 13, 2011, the company received approval from the IURC to significantly improve
Northern Indianas Electric operations ability to purchase customer-generated electricity
from renewable energy projects. The program, supported by consumer and environmental
groups, also allows customers to generate more of their own electricity using renewable
energy to reduce their utility costs.
Construction also remains on schedule for a Flue Gas Desulfurization unit at Northern
Indianas Electric operations Schahfer generating station. This clean-air investment is
part of Northern Indianas $570 to $840 million environmental improvements planned over
the next eight years at Northern Indianas Electric operations electric generating
stations
On July 1, 2011, Columbia of Pennsylvania filed a partial settlement in the companys
base rate case filed on January 14, 2011, with the Pennsylvania Public Utility Commission.
Two items, including rate design for residential customers, will be resolved through a
formal hearing process, and a recommendation is expected this month. If approved, the
settlement will authorize a revenue increase of $17 million annually. A decision is
expected, with new rates in effect, during the fourth quarter of this year.
Table of Contents
NiSources gas distribution companies also remain on track with their infrastructure
modernization and replacement programs designed to ensure safe and reliable service. These
include programs at Columbia of Ohio, Columbia of Pennsylvania, Columbia of Massachusetts
and Columbia of Kentucky. In addition, Columbia of Virginia has filed an application with
its state commission to accelerate recovery of its infrastructure projects. All of these
investments are part of NiSources Gas Distribution Operations more than $4 billion
replacement program scheduled over the next 20 to 25 years.
In the Marcellus region, NiSources Gas Transmission & Storage Operations completed its
Southern Appalachian and Clendenin projects during the second quarter, providing more than
180,000 Dth per day of contracted firm transportation capacity for its customers. Other
Marcellus-related projects in progress include the Rimersburg Expansion in central
Pennsylvania, the Smithfield project in West Virginia and the Line WB Expansion in Virginia
and Kentucky. These producer-driven projects, of which a significant portion are fully
subscribed with long-term contracts or binding precedent agreements, will add up to 525,000
Dth per day of firm transportation.
In addition to its supply-driven Marcellus development activities, NiSources Gas
Transmission & Storage Operations continues to actively develop infrastructure projects to
serve new natural gas-fueled electric generation markets, involving both new natural
gas-fired generation facilities as well as coal conversion opportunities. For example, in
May, Columbia Transmission filed an application with the FERC to construct the pipeline
infrastructure to serve a new contract with Virginia Power Services Energy Corporations
planned 1,329 MW gas-fired generation facility to be owned by Virginia Electric Power
Company in Warren County, Va. The project would provide approximately 250,000 Dth per day
of long-term, firm transportation with an in-service date of mid-2014.
On the regulatory front, Columbia Gulf placed new rates into effect, subject to refund,
on May 1, 2011, as part of its November 2010 rate case filing with the FERC. Columbia Gulf
and the parties to the case are actively engaged in settlement discussions to resolve the
case.
Table of Contents
Quarter Ended June 30, 2011
Gas Distribution Operations net revenues increased due primarily to the impact of
colder weather of approximately $10 million and increased residential and commercial
margins of $9.1 million primarily as a result of Northern Indianas change from a
volumetric-based rate design to one with a higher fixed charge. The new rate design
provides a greater proportion of recovery through the monthly fixed customer charge as
opposed to the volumetric charge for certain customer classes. The revenue variance
experienced in the second quarter from Northern Indianas rate design change is offset
during the periods of higher usage throughout the year. Additionally, there was an
increase of $8.0 million for other regulatory and service programs, including impacts from
the implementation of rates under Columbia of Ohios approved infrastructure replacement
program and rate cases at various other utilities. The change in net revenues was also
positively impacted by a $5.7 million contract reserve that was established in 2010. The
increase in net revenues was partially offset by a decrease of $16.3 million in off-system
sales as a result of the standard service offer auction at Columbia of Ohio in the second
quarter of 2010 and a decrease in net regulatory and tax trackers of $1.7 million, which
are offset in expense.
Gas Transmission and Storage Operations net revenues increased primarily due to higher
demand margin revenue of $8.6 million as a result of growth projects placed into service in
the second half of the prior year. Additionally, there was an increase of $5.7 million due
to the impact of the rate case filing at Columbia Gulf, subject to refund. Net revenues
also increased due to a one-time settlement of $2.8 million, higher condensate revenue of
$2.3 million and increased commodity margin revenue of $2.2 million. These increases in net
revenues were partially offset by the impact of $5.4 million of fees received from a
contract buy-out during the second quarter of 2010.
Electric Operations net revenues increased primarily due to increased industrial usage
and margins of $6.1 million resulting from improved economic conditions and $2.7 million in
lower revenue credits compared to the prior year. These increases were partially offset by
a decrease of $4.6 million in residential and commercial margins and a decrease of $2.2
million in environmental trackers that are partly offset in operating expense.
Table of Contents
Six Months Ended June 30, 2011
Table of Contents
Electric Operations net revenues increased primarily due to increased industrial usage
and margins of $16.4 million resulting from improved economic conditions and $3.9 million
in lower revenue credits compared to the prior year. Additionally, net revenues increased
due to the impact of weather of approximately $3.0 million. These increases were partially
offset by a decrease of $7.6 million in residential and commercial margins.
Gas Transmission and Storage Operations net revenues increased primarily due to higher
demand margin revenue of $13.9 million as a result of growth projects placed into service
in the second half of the prior year. Additionally, there was an increase of $5.7 million
due to the impact of the rate case filing at Columbia Gulf, subject to refund. Net revenues
also increased due to higher condensate revenue of $3.7 million, increased commodity margin
revenue of $3.7 million, increased mineral rights royalty revenues of $3.0 million and a
one-time settlement of $2.8 million. These increases in net revenues were partially offset
by the impact of $8.3 million related to the recognition in 2010 of revenue for a
previously deferred gain for native gas contributed to Hardy Storage Company from Columbia
Transmission following Hardy Storage securing permanent financing. Additionally, revenues
decreased due to the impact of $5.4 million of fees received from a contract buy-out during
the second quarter of 2010 and lower shorter term transportation and storage services of
$4.0 million.
Gas Distribution Operations net revenues decreased due primarily to decreases in net
regulatory and tax trackers of $18.6 million, which are offset in expense, and lower
off-system sales of $17.9 million as a result of the standard service offer auction at
Columbia of Ohio in the second quarter of 2010. Additionally, there was a $7.1 million
decrease in residential, commercial and industrial margins due primarily to Northern
Indianas change from a volumetric-based rate design to one with a higher fixed charge. The
new rate design provides a greater proportion of recovery through the monthly fixed
customer charge as opposed to the volumetric charge for certain customer classes. The
revenue variance experienced from Northern Indianas rate design change is offset
throughout the year. The decreases in net revenues were partially offset by an increase of
$14.4 million for other regulatory and service programs, including impacts from rate cases
at various other utilities and the implementation of new rates under Columbia of Ohios
approved infrastructure replacement program. Additionally, there were increases of
approximately $13 million due to the impact of colder weather, $5.7 million as the result
of a contract reserve that was established in 2010, and $2.4 million from Bear Garden
Station which was placed into service in July of 2010.
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Table of Contents
Table of Contents
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Table of Contents
Table of Contents
Table of Contents
Gas Distribution Operations
Three Months Ended
Six Months Ended
June 30,
June 30,
(in millions)
2011
2010
2011
2010
$
629.9
$
554.7
$
2,215.4
$
2,105.9
316.9
255.5
1,314.8
1,197.5
313.0
299.2
900.6
908.4
187.3
184.8
429.4
443.0
43.7
63.4
86.6
125.9
0.1
35.6
32.5
96.5
85.9
266.6
280.7
612.6
654.8
$
46.4
$
18.5
$
288.0
$
253.6
$
371.7
$
295.7
$
1,447.4
$
1,193.5
110.4
88.9
470.6
405.1
46.3
37.6
124.1
114.6
92.9
87.3
169.7
171.9
8.6
45.2
3.6
220.8
$
629.9
$
554.7
$
2,215.4
$
2,105.9
33.6
25.9
168.1
155.2
26.7
23.2
104.3
96.0
100.8
85.1
219.7
186.0
20.4
27.2
37.9
43.1
0.2
0.2
0.5
0.7
181.7
161.6
530.5
481.0
566
408
3,580
3,298
608
608
3,508
3,508
(7
%)
(33
%)
2
%
(6
%)
3,005,423
3,003,035
277,508
275,246
7,648
7,707
64
81
3,290,643
3,286,069
Table of Contents
Gas Distribution Operations (continued)
Table of Contents
Gas Distribution Operations (continued)
Table of Contents
Gas Transmission and Storage Operations
Three Months Ended
Six Months Ended
June 30,
June 30,
(in millions)
2011
2010
2011
2010
$
174.7
$
161.7
$
374.4
$
358.9
49.4
49.7
99.9
99.1
9.4
5.9
14.6
15.9
233.5
217.3
488.9
473.9
103.2
96.4
197.7
188.2
32.8
31.5
65.5
63.0
(0.1
)
15.1
14.9
27.8
29.8
151.1
142.8
291.0
280.9
2.3
0.4
5.3
7.8
$
84.7
$
74.9
$
203.2
$
200.8
204.9
171.5
631.5
559.0
263.1
197.1
507.1
400.0
5.6
5.6
10.7
13.7
(147.7
)
(142.6
)
(300.3
)
(281.6
)
325.9
231.6
849.0
691.1
Table of Contents
Gas Transmission and Storage Operations (continued)
Table of Contents
Gas Transmission and Storage Operations (continued)
Table of Contents
Gas Transmission and Storage Operations (continued)
Table of Contents
Gas Transmission and Storage Operations (continued)
Table of Contents
Electric Operations
Three Months Ended
Six Months Ended
June 30,
June 30,
(in millions)
2011
2010
2011
2010
$
351.0
$
342.5
$
700.0
$
662.5
136.7
130.9
269.9
247.5
214.3
211.6
430.1
415.0
108.1
94.7
205.3
186.0
53.3
52.9
112.4
105.2
13.1
14.4
29.4
29.1
174.5
162.0
347.1
320.3
$
39.8
$
49.6
$
83.0
$
94.7
89.4
88.0
186.9
177.0
95.0
89.9
187.5
175.2
147.6
125.4
302.8
241.8
6.8
6.1
9.0
11.1
12.2
33.1
13.8
57.4
351.0
342.5
700.0
662.5
784.4
810.5
1,640.2
1,657.5
946.6
952.0
1,871.5
1,887.3
2,325.7
2,111.0
4,768.1
4,141.8
200.2
172.3
267.3
305.7
37.1
39.8
81.6
81.2
4,294.0
4,085.6
8,628.7
8,073.5
258
277
258
277
230
230
230
230
12
%
20
%
12
%
20
%
399,473
399,856
53,861
53,656
2,425
2,426
15
15
737
742
456,511
456,695
Table of Contents
Electric Operations (continued)
Table of Contents
Electric Operations (continued)
Table of Contents
Table of Contents
75
76
77
Table of Contents
Table of Contents
(10.1)
Form of Restricted Stock Unit Award Agreement for Nonemployee Directors under the 2010
Omnibus Incentive Plan.
(31.1)
Certification of Robert C. Skaggs, Jr., Chief Executive Officer, pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
(31.2)
Certification of Stephen P. Smith, Chief Financial Officer, pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
(32.1)
Certification of Robert C. Skaggs, Jr., Chief Executive Officer, pursuant to Section 906
of the Sarbanes-Oxley Act of 2002 (furnished herewith).
(32.2)
Certification of Stephen P. Smith, Chief Financial Officer, pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 (furnished herewith).
Table of Contents
78
NiSource Inc.
(Registrant)
By:
/s/ Jon D. Veurink
Jon D. Veurink
Vice President and Chief Accounting Officer
(Principal Accounting Officer
and Duly Authorized Officer)
1
2
(a) | Unless and until Shares have been issued to the Grantee, the Grantee shall not have any privileges of a stockholder of the Company with respect to any Restricted Stock Units subject to this Agreement; provided, however, that the Grantee shall be entitled to receive dividend equivalent credits equal to the dividends or other distributions declared on any Shares underlying the RSUs in accordance with Section 2. | ||
(b) | Nothing in this Agreement or the Award shall confer upon the Grantee any right to continue as a Nonemployee Director of the Company or any Affiliate or to interfere in any way with the right of the Company or any Affiliate to terminate the Grantees service at any time. |
3
4
5
1. | I have reviewed this Quarterly Report of NiSource Inc. on Form 10-Q for the quarter ended June 30, 2011; | ||
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; | ||
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; | ||
4. | The registrants other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | ||
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; | ||
c) | Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | ||
d) | Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
5. | The registrants other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrants board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and | ||
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
Date: August 2, 2011 | By: | /s/ Robert C. Skaggs, Jr. | ||
Robert C. Skaggs, Jr. | ||||
Chief Executive Officer |
1. | I have reviewed this Quarterly Report of NiSource Inc. on Form 10-Q for the quarter ended June 30, 2011; | ||
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; | ||
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; | ||
4. | The registrants other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | ||
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; | ||
c) | Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | ||
d) | Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
5. | The registrants other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrants board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and | ||
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
Date: August 2, 2011 | By: | /s/ Stephen P. Smith | ||
Stephen P. Smith | ||||
Executive Vice President and
Chief Financial Officer |
||||
(1) | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and | |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. |
/s/ Robert C. Skaggs, Jr. | ||||
Robert C. Skaggs, Jr. | ||||
Chief Executive Officer | ||||
(1) | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and | |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. |
/s/ Stephen P. Smith | ||||
Stephen P. Smith | ||||
Executive Vice President and
Chief Financial Officer |
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