Attached files
file | filename |
---|---|
EX-31.1 - SECTION 302 CERTIFICATION OF JOHN W. GIBSON - ONEOK INC /NEW/ | exhibit_31-1.htm |
EX-32.2 - SECTION 906 CERTIFICATION OF CURTIS L. DINAN - ONEOK INC /NEW/ | exhibit_32-2.htm |
EX-32.1 - SECTION 906 CERTIFICATION OF JOHN W. GIBSON - ONEOK INC /NEW/ | exhibit_32-1.htm |
EX-31.2 - SECTION 302 CERTIFICATION OF CURTIS L. DINAN - ONEOK INC /NEW/ | exhibit_31-2.htm |
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
X Quarterly Report
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934
For the
quarterly period ended June 30, 2010
OR
___
Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act
of 1934
For the
transition period from __________ to __________.
Commission
file number 001-13643
ONEOK,
Inc.
(Exact
name of registrant as specified in its charter)
Oklahoma
|
73-1520922
|
(State
or other jurisdiction of
incorporation
or organization)
|
(I.R.S.
Employer Identification No.)
|
100
West Fifth Street, Tulsa, OK
|
74103
|
(Address
of principal executive offices)
|
(Zip
Code)
|
Registrant’s
telephone number, including area code (918) 588-7000
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports) and (2) has been subject to such filing requirements for
the past 90 days. Yes X No __
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every
Interactive
Data File required to be submitted and posted pursuant to Rule 405 of Regulation
S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such
shorter period that the registrant was required to submit and post such
files). Yes X No __
Indicate
by checkmark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See
the definitions of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act.
Large
accelerated filer X Accelerated
filer
__ Non-accelerated
filer
__ Smaller
reporting company__
Indicate
by checkmark whether the registrant is a shell company (as defined in Rule 12b-2
of the Exchange Act).
Yes __ No
X
On July
28, 2010, the Company had 106,418,886 shares of common stock
outstanding.
ONEOK,
Inc.
TABLE
OF CONTENTS
Part
I.
|
Financial
Information
|
Page
No.
|
Item
1.
|
Financial
Statements (Unaudited)
|
|
Consolidated
Statements of Income - Three and Six Months Ended June 30, 2010 and
2009
|
5
|
|
Consolidated
Balance Sheets - June 30, 2010, and December 31, 2009
|
6-7
|
|
Consolidated
Statements of Cash Flows - Six Months Ended June 30, 2010 and
2009
|
9
|
|
Consolidated
Statement of Changes in Equity - Six Months Ended June 30,
2010
|
10-11
|
|
Consolidated
Statements of Comprehensive Income - Three and Six Months Ended June 30,
2010 and 2009
|
12
|
|
Notes
to Consolidated Financial Statements
|
13-34
|
|
Item
2.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
|
35-56
|
Item
3.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
56-57
|
Item
4.
|
Controls
and Procedures
|
58
|
Part
II.
|
Other
Information
|
|
Item
1.
|
Legal
Proceedings
|
58
|
Item
1A.
|
Risk
Factors
|
58
|
Item
2.
|
Unregistered
Sales of Equity Securities and Use of Proceeds
|
59
|
Item
3.
|
Defaults
Upon Senior Securities
|
59
|
Item
4.
|
(Removed
and Reserved)
|
59
|
Item
5.
|
Other
Information
|
59
|
Item
6.
|
Exhibits
|
59-60
|
Signature
|
61 |
As used
in this Quarterly Report, references to “we,” “our” or “us” refer to ONEOK,
Inc., an Oklahoma corporation, and its predecessors and subsidiaries, unless the
context indicates otherwise.
The
statements in this Quarterly Report that are not historical information,
including statements concerning plans and objectives of management for future
operations, economic performance or related assumptions, are forward-looking
statements. Forward-looking statements may include words such as
“anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,”
“should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,”
“potential,” “scheduled” and other words and terms of similar
meaning. Although we believe that our expectations regarding future
events are based on reasonable assumptions, we can give no assurance that such
expectations and assumptions will be achieved. Important factors that
could cause actual results to differ materially from those in the
forward-looking statements are described under Part I, Item 2, Management’s
Discussion and Analysis of Financial Condition and Results of Operations,
“Forward-Looking Statements” and Part II, Item 1A, “Risk Factors” in this
Quarterly Report and under Part I, Item 1A, “Risk Factors,” in our Annual
Report.
INFORMATION
AVAILABLE ON OUR WEB SITE
We make
available on our Web site copies of our Annual Report, Quarterly Reports,
Current Reports on Form 8-K, amendments to those reports filed or furnished to
the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of
holdings of our securities filed by our officers and directors under Section 16
of the Exchange Act as soon as reasonably practicable after filing such material
electronically or otherwise furnishing it to the SEC. Our Web site
and any contents thereof are not incorporated by reference into this
report.
We also
make available on our Web site the Interactive Data Files required to be
submitted and posted pursuant to Rule 405 of Regulation S-T. In
accordance with Rule 402 of Regulation S-T, the Interactive Data Files shall not
be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or
otherwise subject to the liability of that section, and shall not be
incorporated by reference into any registration statement or other document
filed under the Securities Act or the Exchange Act, except as shall be expressly
set forth by specific reference in such filing.
2
GLOSSARY
The
abbreviations, acronyms and industry terminology used in this Quarterly Report
are defined as follows:
|
AFUDC.............................................................
|
Allowance
for funds used during construction
|
|
Annual
Report.................................................
|
Annual
Report on Form 10-K for the year ended December 31,
2009
|
|
ASU...................................................................
|
Accounting
Standards Update
|
|
Bbl.....................................................................
|
Barrels,
one barrel is equivalent to 42 United States
gallons
|
|
Bbl/d..................................................................
|
Barrels
per day
|
|
BBtu/d...............................................................
|
Billion
British thermal units per day
|
|
Bcf.....................................................................
|
Billion
cubic feet
|
|
Bcf/d..................................................................
|
Billion
cubic feet per day
|
|
Btu(s)................................................................
|
British
thermal units, a measure of the amount of heat required to raise the
temperature of
one pound of water one degree
Fahrenheit
|
|
Bushton
Plant..................................................
|
Bushton
Gas Processing Plant
|
|
Clean
Air Act...................................................
|
Federal
Clean Air Act, as amended
|
|
Clean
Water Act..............................................
|
Federal
Water Pollution Control Act Amendments of 1972, as
amended
|
|
EBITDA............................................................
|
Earnings
before interest, taxes, depreciation and
amortization
|
|
EPA...................................................................
|
United
States Environmental Protection
Agency
|
|
Exchange
Act...................................................
|
Securities
Exchange Act of 1934, as amended
|
|
FASB.................................................................
|
Financial
Accounting Standards Board
|
|
FERC.................................................................
|
Federal
Energy Regulatory Commission
|
|
GAAP................................................................
|
Accounting
principles generally accepted in the United States of
America
|
|
KCC...................................................................
|
Kansas
Corporation Commission
|
|
KDHE................................................................
|
Kansas
Department of Health and
Environment
|
|
LDCs.................................................................
|
Local
distribution companies
|
|
LIBOR...............................................................
|
London
Interbank Offered Rate
|
|
MBbl.................................................................
|
Thousand
barrels
|
|
MBbl/d..............................................................
|
Thousand
barrels per day
|
|
Mcf....................................................................
|
Thousand
cubic feet
|
|
MMBbl.............................................................
|
Million
barrels
|
|
MMBtu.............................................................
|
Million
British thermal units
|
|
MMBtu/d.........................................................
|
Million
British thermal units per day
|
|
MMcf................................................................
|
Million
cubic feet
|
|
MMcf/d............................................................
|
Million
cubic feet per day
|
|
Moody’s...........................................................
|
Moody’s
Investors Service, Inc.
|
|
NGL
products..................................................
|
Marketable
natural gas liquid purity products, such as ethane, ethane/propane mix,
propane,
iso-butane, normal butane and natural
gasoline
|
|
NGL(s)...............................................................
|
Natural
gas liquid(s)
|
|
Northern
Border Pipeline...............................
|
Northern
Border Pipeline Company
|
|
NYMEX............................................................
|
New
York Mercantile Exchange
|
|
OBPI..................................................................
|
ONEOK
Bushton Processing Inc.
|
|
OCC...................................................................
|
Oklahoma
Corporation Commission
|
|
ONEOK.............................................................
|
ONEOK,
Inc.
|
|
ONEOK
Credit Agreement.............................
|
ONEOK’s
$1.2 billion Amended and Restated Credit Agreement dated
July 14,
2006
|
|
|
ONEOK
Partners.............................................
|
ONEOK
Partners, L.P.
|
|
ONEOK
Partners Credit Agreement.............
|
ONEOK
Partners’ $1.0 billion Amended and Restated Revolving Credit
Agreement dated
March 30, 2007
|
|
ONEOK
Partners GP.......................................
|
ONEOK
Partners GP, L.L.C., a wholly owned subsidiary of ONEOK and the
sole
general
partner of ONEOK Partners
|
|
OPIS..................................................................
|
Oil
Price Information Service
|
|
Overland
Pass Pipeline Company.................
|
Overland
Pass Pipeline Company LLC
|
|
Quarterly
Report(s).........................................
|
Quarterly
Report(s) on Form 10-Q
|
|
S&P...................................................................
|
Standard
& Poor’s Rating Group
|
|
SEC....................................................................
|
Securities
and Exchange Commission
|
|
Securities
Act..................................................
|
Securities
Act of 1933, as amended
|
|
Viking
Gas Transmission...............................
|
Viking
Gas Transmission Company
|
|
XBRL.................................................................
|
eXtensible
Business Reporting Language
|
3
This page
intentionally left blank.
4
PART
I - FINANCIAL INFORMATION
|
||||||||||||||||
ITEM
1. FINANCIAL STATEMENTS
|
||||||||||||||||
ONEOK,
Inc. and Subsidiaries
|
||||||||||||||||
CONSOLIDATED STATEMENTS
OF INCOME
|
||||||||||||||||
Three
Months Ended
|
Six
Months Ended
|
|||||||||||||||
June
30,
|
June
30,
|
|||||||||||||||
(Unaudited)
|
2010
|
2009
|
2010
|
2009
|
||||||||||||
(Thousands
of dollars, except per share amounts)
|
||||||||||||||||
Revenues
|
$ | 2,807,131 | $ | 2,227,627 | $ | 6,731,098 | $ | 5,017,454 | ||||||||
Cost
of sales and fuel
|
2,349,054 | 1,795,201 | 5,653,701 | 4,033,617 | ||||||||||||
Net
margin
|
458,077 | 432,426 | 1,077,397 | 983,837 | ||||||||||||
Operating
expenses
|
||||||||||||||||
Operations
and maintenance
|
178,478 | 184,874 | 358,750 | 346,593 | ||||||||||||
Depreciation
and amortization
|
75,510 | 71,249 | 153,367 | 143,375 | ||||||||||||
General
taxes
|
25,103 | 25,261 | 48,176 | 50,488 | ||||||||||||
Total
operating expenses
|
279,091 | 281,384 | 560,293 | 540,456 | ||||||||||||
Gain
(loss) on sale of assets
|
(273 | ) | 3,762 | (1,058 | ) | 4,426 | ||||||||||
Operating
income
|
178,713 | 154,804 | 516,046 | 447,807 | ||||||||||||
Equity
earnings from investments (Note J)
|
20,676 | 14,188 | 41,792 | 35,410 | ||||||||||||
Allowance
for equity funds used during construction
|
235 | 9,468 | 482 | 18,471 | ||||||||||||
Other
income
|
711 | 7,939 | 3,620 | 9,604 | ||||||||||||
Other
expense
|
(7,552 | ) | (1,399 | ) | (8,606 | ) | (5,343 | ) | ||||||||
Interest
expense
|
(75,361 | ) | (73,392 | ) | (151,881 | ) | (151,353 | ) | ||||||||
Income
before income taxes
|
117,422 | 111,608 | 401,453 | 354,596 | ||||||||||||
Income
taxes
|
(31,048 | ) | (30,258 | ) | (128,359 | ) | (109,697 | ) | ||||||||
Net
income
|
86,374 | 81,350 | 273,094 | 244,899 | ||||||||||||
Less:
Net income attributable to noncontrolling interests
|
44,650 | 39,671 | 76,831 | 80,935 | ||||||||||||
Net
income attributable to ONEOK
|
$ | 41,724 | $ | 41,679 | $ | 196,263 | $ | 163,964 | ||||||||
Earnings
per share of common stock (Note K)
|
||||||||||||||||
Net
earnings per share, basic
|
$ | 0.39 | $ | 0.40 | $ | 1.85 | $ | 1.56 | ||||||||
Net
earnings per share, diluted
|
$ | 0.39 | $ | 0.39 | $ | 1.82 | $ | 1.55 | ||||||||
Average
shares of common stock (thousands)
|
||||||||||||||||
Basic
|
106,356 | 105,335 | 106,244 | 105,249 | ||||||||||||
Diluted
|
107,838 | 105,950 | 107,624 | 105,848 | ||||||||||||
Dividends
declared per share of common stock
|
$ | 0.44 | $ | 0.40 | $ | 0.88 | $ | 0.80 | ||||||||
See
accompanying Notes to Consolidated Financial Statements.
|
5
ONEOK,
Inc. and Subsidiaries
|
||||||||
CONSOLIDATED
BALANCE SHEETS
|
||||||||
June
30,
|
December
31,
|
|||||||
(Unaudited)
|
2010
|
2009
|
||||||
Assets
|
(Thousands
of dollars)
|
|||||||
Current
assets
|
||||||||
Cash
and cash equivalents
|
$ | 103,251 | $ | 29,399 | ||||
Accounts
receivable, net
|
904,325 | 1,437,994 | ||||||
Gas
and natural gas liquids in storage
|
572,941 | 583,127 | ||||||
Commodity
imbalances
|
71,289 | 186,015 | ||||||
Energy
marketing and risk management assets (Notes B and C)
|
88,183 | 113,039 | ||||||
Other
current assets
|
138,266 | 238,890 | ||||||
Total
current assets
|
1,878,255 | 2,588,464 | ||||||
Property,
plant and equipment
|
||||||||
Property,
plant and equipment
|
10,304,502 | 10,145,800 | ||||||
Accumulated
depreciation and amortization
|
2,457,162 | 2,352,142 | ||||||
Net
property, plant and equipment
|
7,847,340 | 7,793,658 | ||||||
Investments
and other assets
|
||||||||
Goodwill
and intangible assets
|
1,026,726 | 1,030,560 | ||||||
Energy
marketing and risk management assets (Notes B and C)
|
19,686 | 23,125 | ||||||
Investments
in unconsolidated affiliates
|
757,232 | 765,163 | ||||||
Other
assets
|
590,672 | 626,713 | ||||||
Total
investments and other assets
|
2,394,316 | 2,445,561 | ||||||
Total
assets
|
$ | 12,119,911 | $ | 12,827,683 | ||||
See
accompanying Notes to Consolidated Financial Statements.
|
6
ONEOK,
Inc. and Subsidiaries
|
||||||||
CONSOLIDATED
BALANCE SHEETS
|
||||||||
June
30,
|
December
31,
|
|||||||
(Unaudited)
|
2010
|
2009
|
||||||
Liabilities
and equity
|
(Thousands
of dollars)
|
|||||||
Current
liabilities
|
||||||||
Current
maturities of long-term debt
|
$ | 643,225 | $ | 268,215 | ||||
Notes
payable (Note E)
|
680,000 | 881,870 | ||||||
Accounts
payable
|
830,015 | 1,240,207 | ||||||
Commodity
imbalances
|
205,967 | 394,971 | ||||||
Energy
marketing and risk management liabilities (Notes B and C)
|
35,628 | 65,162 | ||||||
Other
current liabilities
|
480,773 | 488,487 | ||||||
Total
current liabilities
|
2,875,608 | 3,338,912 | ||||||
Long-term
debt, excluding current maturities
|
3,697,585 | 4,334,204 | ||||||
Deferred
credits and other liabilities
|
||||||||
Deferred
income taxes
|
1,053,931 | 1,037,665 | ||||||
Energy
marketing and risk management liabilities (Notes B and C)
|
5,081 | 8,926 | ||||||
Other
deferred credits
|
617,132 | 662,514 | ||||||
Total
deferred credits and other liabilities
|
1,676,144 | 1,709,105 | ||||||
Commitments
and contingencies (Note H)
|
||||||||
Equity
(Note F)
|
||||||||
ONEOK
shareholders' equity:
|
||||||||
Common
stock, $0.01 par value:
|
||||||||
authorized
300,000,000 shares; issued 122,676,368 shares and
outstanding
|
||||||||
106,415,009
shares at June 30, 2010; issued 122,394,015 shares and
|
||||||||
outstanding
105,906,776 shares at December 31, 2009
|
1,227 | 1,224 | ||||||
Paid-in
capital
|
1,375,090 | 1,322,340 | ||||||
Accumulated
other comprehensive loss (Note D)
|
(103,486 | ) | (118,613 | ) | ||||
Retained
earnings
|
1,788,501 | 1,685,710 | ||||||
Treasury
stock, at cost: 16,261,359 shares at June 30, 2010 and
|
||||||||
16,487,239
shares at December 31, 2009
|
(674,103 | ) | (683,467 | ) | ||||
Total
ONEOK shareholders' equity
|
2,387,229 | 2,207,194 | ||||||
Noncontrolling
interests in consolidated subsidiaries
|
1,483,345 | 1,238,268 | ||||||
Total
equity
|
3,870,574 | 3,445,462 | ||||||
Total
liabilities and equity
|
$ | 12,119,911 | $ | 12,827,683 | ||||
See
accompanying Notes to Consolidated Financial Statements.
|
7
This page
intentionally left blank.
8
ONEOK,
Inc. and Subsidiaries
|
||||||||
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
||||||||
Six
Months Ended
|
||||||||
June
30,
|
||||||||
(Unaudited)
|
2010
|
2009
|
||||||
(Thousands
of dollars)
|
||||||||
Operating
activities
|
||||||||
Net
income
|
$ | 273,094 | $ | 244,899 | ||||
Depreciation
and amortization
|
153,367 | 143,375 | ||||||
Allowance
for equity funds used during construction
|
(482 | ) | (18,471 | ) | ||||
Loss
(gain) on sale of assets
|
1,058 | (4,426 | ) | |||||
Equity
earnings from investments
|
(41,792 | ) | (35,410 | ) | ||||
Distributions
received from unconsolidated affiliates
|
39,034 | 38,233 | ||||||
Deferred
income taxes
|
42,794 | 40,865 | ||||||
Share-based
compensation expense
|
10,205 | 8,551 | ||||||
Other
|
3,416 | (767 | ) | |||||
Changes
in assets and liabilities:
|
||||||||
Accounts
receivable
|
531,537 | 492,441 | ||||||
Gas
and natural gas liquids in storage
|
1,618 | 285,271 | ||||||
Accounts
payable
|
(407,513 | ) | (324,364 | ) | ||||
Commodity
imbalances, net
|
(74,278 | ) | (18,352 | ) | ||||
Unrecovered
purchased gas costs
|
89,026 | 42,766 | ||||||
Energy
marketing and risk management assets and liabilities
|
64,050 | 35,373 | ||||||
Fair
value of firm commitments
|
(68,968 | ) | 179,582 | |||||
Other
assets and liabilities
|
(25,039 | ) | (33,714 | ) | ||||
Cash
provided by operating activities
|
591,127 | 1,075,852 | ||||||
Investing
activities
|
||||||||
Changes
in investments in unconsolidated affiliates
|
9,448 | 17,393 | ||||||
Capital
expenditures (less allowance for equity funds used during
construction)
|
(179,704 | ) | (407,600 | ) | ||||
Proceeds
from sale of assets
|
371 | 10,029 | ||||||
Cash
used in investing activities
|
(169,885 | ) | (380,178 | ) | ||||
Financing
activities
|
||||||||
Repayment
of notes payable, net
|
(201,870 | ) | (710,090 | ) | ||||
Repayment
of notes payable with maturities over 90 days
|
- | (870,000 | ) | |||||
Issuance
of debt, net of discounts
|
- | 498,325 | ||||||
Long-term
debt financing costs
|
- | (4,000 | ) | |||||
Repayment
of debt
|
(256,543 | ) | (107,970 | ) | ||||
Repurchase
of common stock
|
(5 | ) | (250 | ) | ||||
Issuance
of common stock
|
7,884 | 4,342 | ||||||
Issuance
of common units of ONEOK Partners, net of discounts
|
322,704 | 220,458 | ||||||
Dividends
paid
|
(93,472 | ) | (84,202 | ) | ||||
Distributions
to noncontrolling interests
|
(126,088 | ) | (105,307 | ) | ||||
Cash
used in financing activities
|
(347,390 | ) | (1,158,694 | ) | ||||
Change
in cash and cash equivalents
|
73,852 | (463,020 | ) | |||||
Cash
and cash equivalents at beginning of period
|
29,399 | 510,058 | ||||||
Cash
and cash equivalents at end of period
|
$ | 103,251 | $ | 47,038 | ||||
See
accompanying Notes to Consolidated Financial Statements.
|
9
ONEOK,
Inc. and Subsidiaries
|
||||||||||||||||
CONSOLIDATED
STATEMENT OF CHANGES IN EQUITY
|
||||||||||||||||
ONEOK
Shareholders' Equity
|
||||||||||||||||
Accumulated
|
||||||||||||||||
Common
|
Other
|
|||||||||||||||
Stock
|
Common
|
Paid-in
|
Comprehensive
|
|||||||||||||
(Unaudited)
|
Issued
|
Stock
|
Capital
|
Income
(Loss)
|
||||||||||||
(Shares)
|
(Thousands
of dollars)
|
|||||||||||||||
December
31, 2009
|
122,394,015 | $ | 1,224 | $ | 1,322,340 | $ | (118,613 | ) | ||||||||
Net
income
|
- | - | - | - | ||||||||||||
Other
comprehensive income
|
- | - | - | 15,127 | ||||||||||||
Repurchase
of common stock
|
- | - | - | - | ||||||||||||
Common
stock issued
|
282,353 | 3 | 2,019 | - | ||||||||||||
Common
stock dividends -
|
||||||||||||||||
$0.88
per share
|
- | - | - | - | ||||||||||||
Issuance
of common units of ONEOK Partners
|
- | - | 50,731 | - | ||||||||||||
Distributions
to noncontrolling interests
|
- | - | - | - | ||||||||||||
June
30, 2010
|
122,676,368 | $ | 1,227 | $ | 1,375,090 | $ | (103,486 | ) | ||||||||
See
accompanying Notes to Consolidated Financial Statements.
|
10
ONEOK,
Inc. and Subsidiaries
|
||||||||||||||||
CONSOLIDATED
STATEMENT OF CHANGES IN EQUITY
|
||||||||||||||||
(Continued)
|
||||||||||||||||
ONEOK
Shareholders' Equity
|
|
|||||||||||||||
Noncontrolling
|
||||||||||||||||
Interests
in
|
||||||||||||||||
Retained
|
Treasury
|
Consolidated
|
Total
|
|||||||||||||
(Unaudited)
|
Earnings
|
Stock
|
Subsidiaries
|
Equity
|
||||||||||||
(Thousands
of dollars)
|
||||||||||||||||
December
31, 2009
|
$ | 1,685,710 | $ | (683,467 | ) | $ | 1,238,268 | $ | 3,445,462 | |||||||
Net
income
|
196,263 | - | 76,831 | 273,094 | ||||||||||||
Other
comprehensive income
|
- | - | 22,361 | 37,488 | ||||||||||||
Repurchase
of common stock
|
- | (5 | ) | - | (5 | ) | ||||||||||
Common
stock issued
|
- | 9,369 | - | 11,391 | ||||||||||||
Common
stock dividends -
|
||||||||||||||||
$0.88
per share
|
(93,472 | ) | - | - | (93,472 | ) | ||||||||||
Issuance
of common units of ONEOK Partners
|
- | - | 271,973 | 322,704 | ||||||||||||
Distributions
to noncontrolling interests
|
- | - | (126,088 | ) | (126,088 | ) | ||||||||||
June
30, 2010
|
$ | 1,788,501 | $ | (674,103 | ) | $ | 1,483,345 | $ | 3,870,574 |
11
ONEOK,
Inc. and Subsidiaries
|
||||||||||||||||
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME
|
||||||||||||||||
Three
Months Ended
|
Six
Months Ended
|
|||||||||||||||
June
30,
|
June
30,
|
|||||||||||||||
(Unaudited)
|
2010
|
2009
|
2010
|
2009
|
||||||||||||
(Thousands
of dollars)
|
||||||||||||||||
Net
income
|
$ | 86,374 | $ | 81,350 | $ | 273,094 | $ | 244,899 | ||||||||
Other
comprehensive income (loss), net of tax
|
||||||||||||||||
Unrealized
gains (losses) on energy marketing and risk management
|
||||||||||||||||
assets/liabilities,
net of tax of $(4,689), $9,743, $(23,526) and
|
||||||||||||||||
$(28,340),
respectively
|
14,036 | (22,177 | ) | 57,527 | 38,469 | |||||||||||
Realized
gains in net income, net of tax of $748, $5,176, $8,769
|
||||||||||||||||
and
$32,853, respectively
|
(1,717 | ) | (16,793 | ) | (11,776 | ) | (70,713 | ) | ||||||||
Unrealized
holding gains (losses) on available-for-sale securities,
|
||||||||||||||||
net
of tax of $107, $(200), $168 and $(319), respectively
|
(169 | ) | 318 | (267 | ) | 505 | ||||||||||
Change
in pension and postretirement benefit plan liability, net of
tax
|
||||||||||||||||
of
$2,533, $2,057, $5,066 and $3,655, respectively
|
(4,016 | ) | (3,260 | ) | (8,032 | ) | (5,795 | ) | ||||||||
Other,
net of tax of $(11), $(11), $(22) and $(62), respectively
|
18 | 18 | 36 | 208 | ||||||||||||
Total
other comprehensive income (loss), net of tax
|
8,152 | (41,894 | ) | 37,488 | (37,326 | ) | ||||||||||
Comprehensive
income
|
94,526 | 39,456 | 310,582 | 207,573 | ||||||||||||
Less:
Comprehensive income attributable to noncontrolling
interests
|
50,723 | 24,731 | 99,192 | 55,953 | ||||||||||||
Comprehensive
income attributable to ONEOK
|
$ | 43,803 | $ | 14,725 | $ | 211,390 | $ | 151,620 | ||||||||
See
accompanying Notes to Consolidated Financial Statements.
|
12
ONEOK,
Inc. and Subsidiaries
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
A. SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
Our
accompanying unaudited consolidated financial statements have been prepared in
accordance with GAAP and reflect all adjustments that, in our opinion, are
necessary for a fair presentation of the results for the interim periods
presented. All such adjustments are of a normal recurring
nature. The 2009 year-end consolidated balance sheet data was derived
from audited financial statements but does not include all disclosures required
by GAAP. These unaudited consolidated financial statements should be
read in conjunction with our audited consolidated financial statements in our
Annual Report. Due to the seasonal nature of our business, the
results of operations for the three and six months ended June 30, 2010, are not
necessarily indicative of the results that may be expected for a 12-month
period.
Our
significant accounting policies are consistent with those disclosed in Note A of
the Notes to Consolidated Financial Statements in our Annual
Report.
Recently
Issued Accounting Standards Update
The
following recently issued accounting standards update affects our consolidated
financial statements and related disclosures:
Fair Value Measurements and
Disclosures - In January 2010, the FASB issued ASU 2010-06, “Improving
Disclosures about Fair Value Measurements,” which established new disclosure
requirements and clarified existing requirements for disclosures of fair value
measurements. ASU 2010-06 required us to add two new disclosures, when
applicable: (i) transfers in and out of Level 1 and 2 fair value measurements
including the reasons for the transfers, and (ii) a gross presentation of
activity within the reconciliation of Level 3 fair value
measurements. Except for separate disclosure of purchases, sales,
issuances and settlements in the reconciliation of our Level 3 fair value
measurements, we applied this guidance to our disclosures beginning with our
March 31, 2010, Quarterly Report. The separate disclosure of
purchases, sales, issuances and settlements in the reconciliation of our Level 3
fair value measurements will be required beginning with our March 31, 2011,
Quarterly Report, and we do not expect the impact to be material. ASU
2010-06 requires prospective application in the period of adoption, and we have
not recast our prior-year disclosures. See Note B for more
discussion of our fair value measurements.
Our
policy for calculating transfers between levels of the fair value
hierarchy recognizes the transfer as of the end of each
reporting period. Prior to January 1, 2010, our policy of calculating
transfers recognized transfers in at the end of the reporting period and
transfers out at the beginning of the reporting period.
Therefore, transfers into and out of Level 3 and included in earnings may
not be comparable with prior periods.
B. FAIR
VALUE MEASUREMENTS
Determining Fair Value - We
define fair value as the price that would be received from the sale of an asset
or the transfer of a liability in an orderly transaction between market
participants at the measurement date. We use the market and income
approaches to determine the fair value of our assets and liabilities and
consider the markets in which the transactions are executed. While
many of the contracts in our portfolio are executed in liquid markets where
price transparency exists, some contracts are executed in markets for which
market prices may exist, but the market may be relatively
inactive. This results in limited price transparency that requires
management’s judgment and assumptions to estimate fair values. Inputs
into our fair value estimates include commodity exchange prices,
over-the-counter quotes, volatility, historical correlations of pricing data and
LIBOR, and other liquid money market instrument rates. We also
utilize internally developed basis curves that incorporate observable and
unobservable market data. We validate our valuation inputs with
third-party information and settlement prices from other sources, where
available. In addition, as prescribed by the income approach, we
compute the fair value of our derivative portfolio by discounting the projected
future cash flows from our derivative assets and liabilities to present value
using interest rate yields to calculate present-value discount factors derived
from LIBOR, Eurodollar futures and U.S. Treasury swaps. We also take
into consideration the potential impact on market prices of liquidating
positions in an orderly manner over a reasonable period of time under current
market conditions. We consider current market data in evaluating
counterparties’, as well as our own, nonperformance risk, net of collateral, by
using specific and sector bond yields and also monitoring the credit default
swap markets. Although we use our best estimates to determine the
fair value of
13
the
derivative contracts we have executed, the ultimate market prices realized could
differ from our estimates, and the differences could be material.
Recurring Fair Value
Measurements - The following tables set forth our recurring fair value
measurements for the periods indicated:
June
30, 2010
|
||||||||||||||||||||
Level
1
|
Level
2
|
Level
3
|
Netting
|
Total
|
||||||||||||||||
(Thousands
of dollars)
|
||||||||||||||||||||
Assets
|
||||||||||||||||||||
Derivatives
(a)
|
||||||||||||||||||||
Commodity
contracts
|
||||||||||||||||||||
Financial
contracts
|
$ | 104,965 | $ | 8,173 | $ | 340,770 | $ | - | $ | 453,908 | ||||||||||
Physical
contracts
|
- | 21,841 | 23,245 | - | 45,086 | |||||||||||||||
Netting
|
- | - | - | (391,142 | ) | (391,142 | ) | |||||||||||||
Foreign
Exchange contracts
|
17 | - | - | - | 17 | |||||||||||||||
Total
derivatives
|
104,982 | 30,014 | 364,015 | (391,142 | ) | 107,869 | ||||||||||||||
Trading
securities (b)
|
6,643 | - | - | - | 6,643 | |||||||||||||||
Available-for-sale
investment securities (c)
|
2,252 | - | - | - | 2,252 | |||||||||||||||
Total assets | $ | 113,877 | $ | 30,014 | $ | 364,015 | $ | (391,142 | ) | $ | 116,764 | |||||||||
Liabilities
|
||||||||||||||||||||
Derivatives
(a)
|
||||||||||||||||||||
Commodity
contracts
|
||||||||||||||||||||
Financial
contracts
|
$ | (74,431 | ) | $ | (2,291 | ) | $ | (262,402 | ) | $ | - | $ | (339,124 | ) | ||||||
Physical
contracts
|
- | (4,419 | ) | (12,501 | ) | - | (16,920 | ) | ||||||||||||
Netting
|
- | - | - | 315,348 | 315,348 | |||||||||||||||
Foreign
Exchange contracts
|
(13 | ) | - | - | - | (13 | ) | |||||||||||||
Total
derivatives
|
(74,444 | ) | (6,710 | ) | (274,903 | ) | 315,348 | (40,709 | ) | |||||||||||
Fair
value of firm commitments (d)
|
- | - | (65,653 | ) | - | (65,653 | ) | |||||||||||||
Total liabilities | $ | (74,444 | ) | $ | (6,710 | ) | $ | (340,556 | ) | $ | 315,348 | $ | (106,362 | ) | ||||||
(a)
- Our derivative assets and liabilities are presented in our Consolidated
Balance Sheets as energy marketing and risk management assets and
liabilities on a net basis. We net derivative assets and liabilities,
including cash collateral, when a legally enforceable master-netting
arrangement exists between the counterparty to a derivative contract and
us. At June 30, 2010, we held $78.9 million of cash collateral and
had posted $3.1 million of cash collateral with various
counterparties.
|
||||||||||||||||||||
(b)
- Our trading securities are presented in our Consolidated Balance Sheets
as other current assets.
|
||||||||||||||||||||
(c)
- Our available-for-sale investment securities are presented in our
Consolidated Balance Sheets as other assets.
|
||||||||||||||||||||
(d)
- Our fair value of firm commitments are presented in our Consolidated
Balance Sheets as other current liabilities and other deferred
credits.
|
14
December
31, 2009
|
||||||||||||||||||||
Level
1
|
Level
2
|
Level
3
|
Netting
|
Total
|
||||||||||||||||
(Thousands
of dollars)
|
||||||||||||||||||||
Assets
|
||||||||||||||||||||
Derivatives
(a)
|
$ | 149,034 | $ | 4,898 | $ | 672,631 | $ | (690,399 | ) | $ | 136,164 | |||||||||
Trading
securities (b)
|
7,927 | - | - | - | 7,927 | |||||||||||||||
Available-for-sale
investment securities (c)
|
2,688 | - | - | - | 2,688 | |||||||||||||||
Total
assets
|
$ | 159,649 | $ | 4,898 | $ | 672,631 | $ | (690,399 | ) | $ | 146,779 | |||||||||
Liabilities
|
||||||||||||||||||||
Derivatives
(a)
|
$ | (109,713 | ) | $ | (8,481 | ) | $ | (535,937 | ) | $ | 580,043 | $ | (74,088 | ) | ||||||
Fair
value of firm commitments (d)
|
- | - | (134,620 | ) | - | (134,620 | ) | |||||||||||||
Total
liabilities
|
$ | (109,713 | ) | $ | (8,481 | ) | $ | (670,557 | ) | $ | 580,043 | $ | (208,708 | ) | ||||||
(a)
- Our derivative assets and liabilities are presented in our Consolidated
Balance Sheets as energy marketing and risk management assets and
liabilities on a net basis. We net derivative assets and liabilities,
including cash collateral, when a legally enforceable master-netting
arrangement exists between the counterparty to a derivative contract and
us. At December 31, 2009, we held $136.5 million of cash collateral
and had posted $26.1 million of cash collateral with various
counterparties.
|
||||||||||||||||||||
(b)
- Our trading securities are presented in our Consolidated Balance Sheets
as other current assets.
|
||||||||||||||||||||
(c)
- Our available-for-sale investment securities are presented in our
Consolidated Balance Sheets as other assets.
|
||||||||||||||||||||
(d)
- Our fair value of firm commitments are presented in our Consolidated
Balance Sheets as other current liabilities and other deferred
credits.
|
||||||||||||||||||||
We
categorize derivatives for which fair value is determined using multiple inputs
within a single level, based on the lowest level input that is significant to
the fair value measurement in its entirety.
Our Level 1 fair value
measurements are based on NYMEX-settled prices, actively quoted prices for
equity securities and foreign currency forward-exchange rates. These
balances are predominantly comprised of exchange-traded derivative contracts,
including futures and certain options for natural gas and crude oil, which are
valued based on unadjusted quoted prices in active markets. Also
included in Level 1 are equity securities and foreign currency forwards.
Our Level
2 fair value inputs are based on NYMEX-settled prices for natural gas and crude
oil that are utilized to determine the fair value of certain non-exchange traded
financial instruments, including natural gas and crude oil swaps, as well as
physical forwards.
For the
six months ended June 30, 2010, there were no transfers between levels 1 and
2.
Our Level
3 inputs include internally developed basis curves incorporating observable and
unobservable market data, NGL price curves from a pricing service, historical
correlations of NGL product prices to published NYMEX crude oil prices, market
volatilities derived from the most recent NYMEX close spot prices and forward
LIBOR curves, and adjustments for the credit risk of our
counterparties. We corroborate the data on which our fair value
estimates are based using our market knowledge of recent transactions, analysis
of historical correlations and validation with independent broker quotes or a
pricing service. The derivatives categorized as Level 3 include
natural gas basis swaps, swing swaps, options, NGL swaps, commodity or natural
gas and NGL physical forward contracts and interest-rate swaps. Also
included in Level 3 are the fair values of firm commitments. We do
not believe that our Level 3 fair value estimates have a material impact on our
results of operations, as the majority of our derivatives are accounted for as
hedges for which ineffectiveness is not material.
15
The
following tables set forth the reconciliation of our Level 3 fair value
measurements for the periods indicated:
Derivative
Assets
(Liabilities)
|
Fair
Value of
Firm
Commitments
|
Total
|
|||||||||||
(Thousands
of dollars)
|
|||||||||||||
April
1, 2010
|
$ | 147,573 | $ | (111,597 | ) | $ | 35,976 | ||||||
Total
realized/unrealized gains (losses):
|
|||||||||||||
Included
in earnings
|
(52,606 | ) |
(a)
|
45,944 |
(a)
|
(6,662 | ) | ||||||
Included
in other comprehensive income (loss)
|
8,484 | - | 8,484 | ||||||||||
Transfers
into Level 3
|
431 | - | 431 | ||||||||||
Transfers
out of Level 3
|
(14,770 | ) | - | (14,770 | ) | ||||||||
June
30, 2010
|
$ | 89,112 | $ | (65,653 | ) | $ | 23,459 | ||||||
Total
gains (losses) for the period included in
earnings
attributable to the change in unrealized
gains
(losses) relating to assets and liabilities
still
held as of June 30, 2010 (a)
|
$ | (24,529 | ) | $ | 13,481 | $ | (11,048 | ) | |||||
(a)
- Reported in revenues and cost of sales and fuel in our Consolidated
Statements of Income.
|
Derivative
Assets
(Liabilities)
|
Fair
Value of
Firm
Commitments
|
Total
|
|||||||||||
(Thousands
of dollars)
|
|||||||||||||
April
1, 2009
|
$ | 170,238 | $ | (111,212 | ) | $ | 59,026 | ||||||
Total
realized/unrealized gains (losses):
|
|||||||||||||
Included
in earnings
|
34,202 |
(a)
|
(26,191 | ) |
(a)
|
8,011 | |||||||
Included
in other comprehensive income (loss)
|
(52,330 | ) | - | (52,330 | ) | ||||||||
Transfers
in and/or out of Level 3
|
18,304 | - | 18,304 | ||||||||||
June
30, 2009
|
$ | 170,414 | $ | (137,403 | ) | $ | 33,011 | ||||||
Total
gains (losses) for the period included in
earnings
attributable to the change in unrealized
gains
(losses) relating to assets and liabilities
still
held as of June 30, 2009 (a)
|
$ | 57,041 | $ | (44,189 | ) | $ | 12,852 | ||||||
(a)
- Reported in revenues and cost of sales and fuel in our Consolidated
Statements of Income.
|
Derivative
Assets
(Liabilities)
|
Fair
Value of
Firm
Commitments
|
Total
|
||||||||||
(Thousands
of dollars)
|
||||||||||||
January
1, 2010
|
$ | 136,694 | $ | (134,620 | ) | $ | 2,074 | |||||
Total
realized/unrealized gains (losses):
|
||||||||||||
Included
in earnings (a)
|
(56,032 | ) | 68,967 | 12,935 | ||||||||
Included
in other comprehensive income (loss)
|
21,705 | - | 21,705 | |||||||||
Transfers
into Level 3
|
1,423 | - | 1,423 | |||||||||
Transfers
out of Level 3
|
(14,678 | ) | - | (14,678 | ) | |||||||
June
30, 2010
|
$ | 89,112 | $ | (65,653 | ) | $ | 23,459 | |||||
Total
gains (losses) for the period included in
earnings
attributable to the change in unrealized
gains
(losses) relating to assets and liabilities
still
held as of June 30, 2010 (a)
|
$ | (5,761 | ) | $ | 8,532 | $ | 2,771 | |||||
(a)
- Reported in revenues and cost of sales and fuel in our Consolidated
Statements of Income.
|
16
Derivative
Assets
(Liabilities)
|
Fair
Value of
Firm
Commitments
|
Long-Term
Debt
|
Total
|
|||||||||||||
(Thousands
of dollars)
|
||||||||||||||||
January
1, 2009
|
$ | 42,355 | $ | 42,179 | $ | (171,455 | ) | $ | (86,921 | ) | ||||||
Total
realized/unrealized gains (losses):
|
||||||||||||||||
Included
in earnings
|
188,038 |
(a)
|
(179,582 | ) |
(a)
|
1,455 |
(b)
|
9,911 | ||||||||
Included
in other comprehensive income (loss)
|
(60,060 | ) | - | - | (60,060 | ) | ||||||||||
Maturities
|
- | - | 100,000 | 100,000 | ||||||||||||
Terminations
prior to maturity
|
- | - | 70,000 | 70,000 | ||||||||||||
Transfers
in and/or out of Level 3
|
81 | - | - | 81 | ||||||||||||
June
30, 2009
|
$ | 170,414 | $ | (137,403 | ) | $ | - | $ | 33,011 | |||||||
Total
gains (losses) for the period included in
earnings
attributable to the change in unrealized
gains
(losses) relating to assets and liabilities
still
held as of June 30, 2009 (a)
|
$ | 189,866 | $ | (162,734 | ) | $ | - | $ | 27,132 | |||||||
(a)
- Reported in revenues and cost of sales and fuel in our Consolidated
Statements of Income.
|
||||||||||||||||
(b)
- Reported in interest expense in our Consolidated Statements of
Income.
|
Realized/unrealized
gains (losses) include the realization of our derivative contracts through
maturity and changes in fair value of our hedged firm commitments and fixed-rate
debt swapped to a floating rate. Maturities represent the long-term debt
associated with an interest-rate swap that matured during the
period. Terminations prior to maturity represent the long-term debt
associated with an interest-rate swap that was terminated during the
period. Transfers into Level 3 represent existing assets or
liabilities that were previously categorized at a higher level for which the
unobservable inputs became a more significant portion of the fair value
estimates. Transfers out of Level 3 represent existing assets and
liabilities that were previously classified as Level 3 for which the observable
inputs became a more significant portion of the fair value
estimates.
Other Financial Instruments
- The
approximate fair value of cash and cash equivalents, accounts receivable and
accounts payable is equal to book value, due to the short-term nature of these
items. The fair value of notes payable approximates the carrying
value since the interest rates, prescribed by each borrowing’s respective credit
agreement, are periodically adjusted to reflect current market
conditions.
The
estimated fair value of long-term debt, including current maturities, was $4.6
billion at June 30, 2010, and $4.8 billion at December 31, 2009. The
book value of long-term debt, including current maturities, was $4.3 billion at
June 30, 2010, and $4.6 billion at December 31, 2009. The estimated
fair value of long-term debt has been determined using quoted market prices of
the same or similar issues with similar terms and maturities.
C. RISK
MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES
Our
Energy Services and ONEOK Partners segments are exposed to various risks that we
manage by periodically entering into derivative instruments. These
risks include the following:
·
|
Commodity price
risk - We are exposed to the risk of loss in cash flows and future
earnings arising from adverse changes in the price of natural gas, NGLs
and crude oil. We use commodity derivative instruments such as
futures, physical forward contracts, swaps and options to mitigate the
commodity price risk associated with a portion of the forecasted purchases
and sales of commodities and natural gas and natural gas liquids in
storage;
|
·
|
Basis risk - We
are exposed to the risk of loss in cash flows and future earnings arising
from adverse changes in the price differentials between pipeline receipt
and delivery locations. Our firm transportation capacity allows
us to purchase gas at a pipeline receipt point and sell gas at a pipeline
delivery point. Our Energy Services segment periodically enters
into basis swaps between the transportation receipt and delivery points in
order to protect the fair value of these location price differentials
related to our firm commitments;
and
|
·
|
Currency exchange rate
risk - As a result of our Energy Services segment’s activities in
Canada, we are exposed to the risk of loss in cash flows and future
earnings from adverse changes in currency exchange rates on our commodity
purchases and sales primarily related to our firm transportation and
storage contracts that are transacted in a currency other than our
functional currency, the U.S. dollar. To reduce our exposure to
exchange-rate fluctuations, we use physical forward transactions, which
result in an actual two-way flow of currency on the settlement date in
which we exchange U.S. dollars for Canadian dollars with another
party.
|
17
·
|
Futures
contracts - Standardized exchange-traded contracts to purchase
or sell natural gas or crude oil at a specified price, requiring delivery
on or settlement through the sale or purchase of an offsetting contract by
a specified future date under the provisions of exchange
regulations;
|
·
|
Forward
contracts - Commitments to purchase or sell natural gas, crude
oil or NGLs for delivery at some specified time in the future. We
also use currency forward contracts to manage our currency exchange rate
risk. Forward contracts are different from futures in that forwards are
customized and non-exchange traded;
|
·
|
Swaps -
Financial trades involving the exchange of payments based on two different
pricing structures for a commodity. In a typical commodity swap,
parties exchange payments based on changes in the price of a commodity or
a market index, while fixing the price they effectively pay or receive for
the physical commodity. As a result, one party assumes the risks and
benefits of movements in market prices, while the other party assumes the
risks and benefits of a fixed price for the commodity;
and
|
·
|
Options -
Contractual agreements that give the holder the right, but not the
obligation, to buy or sell a fixed quantity of a commodity, at a fixed
price, within a specified period of time. Options may either be
standardized and exchange traded or customized and non-exchange
traded.
|
Our
objectives for entering into such contracts include but are not limited
to:
·
|
reducing
the variability of cash flows by locking in the price for all or a portion
of anticipated index-based physical purchases and sales, transportation
fuel requirements, asset management transactions and customer-related
business activities;
|
·
|
locking
in a price differential to protect the fair value between transportation
receipt and delivery points and to protect the fair value of natural gas
or NGLs that are purchased in one month and sold in a later month;
and
|
·
|
reducing
our exposure to fluctuations in foreign currency exchange
rates.
|
Our
Energy Services segment also enters into derivative contracts for financial
trading purposes primarily to capitalize on opportunities created by market
volatility, weather-related events, supply-demand imbalances and market
liquidity inefficiency, which allows us to capture additional
margin. Financial trading activities are executed generally using
financially settled derivatives and are normally short term in
nature.
With
respect to the net open positions that exist within our marketing and financial
trading operations, fluctuating commodity prices can impact our financial
position and results of operations. The net open positions are
actively managed, and the impact of the changing prices on our financial
condition at a point in time is not necessarily indicative of the impact of
price movements throughout the year.
Our
Distribution segment also uses derivative instruments to hedge the cost of
anticipated natural gas purchases during the winter heating months to protect
our customers from upward volatility in the market price of natural
gas. The use of these derivative instruments and the associated
recovery of these costs have been approved by the OCC, KCC and regulatory
authorities in most of our Texas jurisdictions.
We are
also subject to fluctuation in interest rates. We manage
interest-rate risk through the use of fixed-rate debt, floating-rate debt and
interest-rate swaps. Interest-rate swaps are agreements to exchange
an interest payment at some future point based on the differential between two
interest rates.
Accounting
Treatment
We record
derivative instruments at fair value, with the exception of normal purchases and
normal sales that are expected to result in physical delivery. The
accounting for changes in the fair value of a derivative instrument depends on
whether it has been designated and qualifies as part of a hedging relationship
and, if so, the reason for holding it.
If
certain conditions are met, we may elect to designate a derivative instrument as
a hedge of exposure to changes in fair values, cash flows or foreign
currency. Certain non-trading derivative transactions, which are
economic hedges of our accrual transactions such as our storage and
transportation contracts, do not qualify for hedge accounting
treatment.
18
The table
below summarizes the various ways in which we account for our derivative
instruments and the impact on our consolidated financial
statements:
Recognition
and Measurement
|
||||||||
Accounting
Treatment
|
Balance
Sheet
|
Income
Statement
|
||||||
Normal
purchases and
normal
sales
|
- |
Fair
value not recorded
|
- |
Change
in fair value not recognized in earnings
|
||||
Mark-to-market
|
- |
Recorded
at fair value
|
- |
Change
in fair value recognized in earnings
|
||||
Cash
flow hedge
|
- |
Recorded
at fair value
|
- |
Ineffective
portion of the gain or loss on the derivative instrument is recognized in
earnings
|
||||
- |
Effective
portion of the gain or loss on the derivative instrument is reported
initially as a component of accumulated other comprehensive income
(loss)
|
- |
Effective
portion of the gain or loss on the derivative instrument is reclassified
out of accumulated other comprehensive income (loss) into earnings when
the forecasted transaction affects earnings
|
|||||
Fair
value hedge
|
- |
Recorded
at fair value
|
- |
The
gain or loss on the derivative instrument is recognized in
earnings
|
||||
- |
Change
in fair value of the hedged item is recorded as an adjustment to book
value
|
- |
Change
in fair value of the hedged item is recognized in
earnings
|
Gains or
losses associated with the fair value of derivative instruments entered into by
our Distribution segment are included in, and recoverable through, the monthly
purchased-gas cost mechanism.
We
formally document all relationships between hedging instruments and hedged
items, as well as risk management objectives, strategies for undertaking various
hedge transactions and methods for assessing and testing correlation and hedge
ineffectiveness. We specifically identify the asset, liability, firm
commitment or forecasted transaction that has been designated as the hedged
item. We assess the effectiveness of hedging relationships quarterly
by performing a regression analysis on our cash flow and fair value hedging
relationships to determine whether the hedge relationships are highly effective
on a retrospective and prospective basis. We also document our normal
purchases and normal sales transactions that we expect to result in physical
delivery and which we elect to exempt from derivative accounting
treatment.
The
presentation of settled derivative instruments on either a gross or net basis in
our Consolidated Statements of Income is dependent on the relevant facts and
circumstances of our different types of activities rather than based solely on
the terms of the individual contracts. All financially settled
derivative instruments, as well as derivative instruments considered held for
trading purposes that result in physical delivery, are reported on a net basis
in revenues in our Consolidated Statements of Income. The realized
revenues and purchase costs of derivative instruments that are not considered
held for trading purposes and non-derivative contracts are reported on a gross
basis. Derivatives that qualify as normal purchases or normal sales
that are expected to result in physical delivery are also reported on a gross
basis.
Revenues
in our Consolidated Statements of Income include financial trading margins, as
well as certain physical natural gas transactions with our trading
counterparties. Revenues and cost of sales and fuel from such
physical transactions are reported on a net basis.
Cash
flows from futures, forwards, options and swaps that are accounted for as hedges
are included in the same Consolidated Statements of Cash Flows category as the
cash flows from the related hedged items.
19
Fair
Values of Derivative Instruments
See
Note B for a discussion of the inputs associated with our fair value
measurements.
The
following table sets forth the fair values of our derivative instruments for the
periods indicated:
June
30, 2010
|
December
31, 2009
|
|||||||||||||
Fair
Values of Derivatives (a)
|
Fair
Values of Derivatives (a)
|
|||||||||||||
Assets
|
(Liabilities)
|
Assets
|
(Liabilities)
|
|||||||||||
(Thousands
of dollars)
|
||||||||||||||
Derivatives
designated as hedging instruments
|
||||||||||||||
Commodity
contracts
|
||||||||||||||
Financial
contracts
|
$ | 187,813 |
(b)
|
$ | (49,132 | ) | $ | 311,009 |
(c)
|
$ | (130,831 | ) | ||
Physical
contracts
|
756 | (176 | ) | 1,702 | (937 | ) | ||||||||
Total
derivatives designated as hedging instruments
|
188,569 | (49,308 | ) | 312,711 | (131,768 | ) | ||||||||
Derivatives
not designated as hedging instruments
|
||||||||||||||
Commodity
contracts
|
||||||||||||||
Non-trading
instruments
|
||||||||||||||
Financial
contracts
|
226,532 | (252,735 | ) | 407,475 | (447,714 | ) | ||||||||
Physical
contracts
|
44,330 | (16,744 | ) | 46,598 | (16,234 | ) | ||||||||
Trading
instruments
|
||||||||||||||
Financial
contracts
|
39,563 | (37,257 | ) | 59,751 | (58,334 | ) | ||||||||
Total
commodity contracts
|
310,425 | (306,736 | ) | 513,824 | (522,282 | ) | ||||||||
Foreign
exchange contracts
|
17 | (13 | ) | 28 | (81 | ) | ||||||||
Total
derivatives not designated as hedging instruments
|
310,442 | (306,749 | ) | 513,852 | (522,363 | ) | ||||||||
Total
derivatives
|
$ | 499,011 | $ | (356,057 | ) | $ | 826,563 | $ | (654,131 | ) | ||||
(a)
- Included on a net basis in energy marketing and risk management assets
and liabilities on our Consolidated Balance Sheets.
|
||||||||||||||
(b)
- Includes $11.3 million of derivative assets associated with cash flow
hedges of inventory that were adjusted to reflect the lower of cost or
market value. The deferred gains associated with these assets have
been reclassified from accumulated other comprehensive
loss.
|
||||||||||||||
(c)
- Includes $37.7 million of derivative assets associated with cash flow
hedges of inventory that were adjusted to reflect the lower of cost or
market value. The deferred gains associated with these assets have
been reclassified from accumulated other comprehensive
loss.
|
||||||||||||||
20
Notional
Quantities for Derivative Instruments
The
following table sets forth the notional quantities for derivative instruments
held for the periods indicated:
June
30, 2010
|
December
31, 2009
|
||||||||||||||||
Contract
Type
|
Purchased/
Payor
|
Sold/
Receiver
|
Purchased/
Payor
|
Sold/
Receiver
|
|||||||||||||
Derivatives
designated as hedging instruments:
|
|||||||||||||||||
Cash flow
hedges
|
|||||||||||||||||
Fixed
price
|
|||||||||||||||||
-
Natural gas (Bcf)
|
Exchange
futures
|
5.4 | (12.5 | ) | 6.4 | (20.7 | ) | ||||||||||
Swaps
|
3.2 | (65.3 | ) | 18.1 | (80.7 | ) | |||||||||||
- Crude
oil and NGLs
(MMBbl)
|
Swaps
|
- | (1.8 | ) | - | (2.4 | ) | ||||||||||
Basis
|
|||||||||||||||||
-
Natural gas (Bcf)
|
Forwards
and swaps
|
8.9 | (71.7 | ) | 23.7 | (99.6 | ) | ||||||||||
Fair value
hedges
|
|||||||||||||||||
Basis
|
|||||||||||||||||
-
Natural gas (Bcf)
|
Forwards
and swaps
|
187.3 | (187.3 | ) | 210.4 | (210.4 | ) | ||||||||||
Derivatives
not designated as hedging instruments:
|
|||||||||||||||||
Fixed
price
|
|||||||||||||||||
-
Natural gas (Bcf)
|
Exchange
futures
|
23.9 | (15.0 | ) | 38.8 | (22.7 | ) | ||||||||||
Forwards
and swaps
|
83.3 | (104.0 | ) | 100.6 | (117.4 | ) | |||||||||||
Options
|
115.4 | (75.1 | ) | 102.6 | (80.6 | ) | |||||||||||
- Crude
and NGLs (MBbl)
|
Forwards
and swaps
|
1.1 | (1.6 | ) | - | - | |||||||||||
-
Foreign currency
(Millions of dollars)
|
Swaps
|
$ | 1.6 | $ | - | $ | 4.6 | $ | - | ||||||||
Basis
|
|||||||||||||||||
-
Natural gas (Bcf)
|
Forwards
and swaps
|
704.2 | (708.7 | ) | 940.7 | (947.1 | ) | ||||||||||
Index
|
|||||||||||||||||
-
Natural gas
(Bcf)
|
Forwards
and swaps
|
46.8 | (11.0 | ) | 66.4 | (33.1 | ) |
These
notional amounts are used to summarize the volume of financial
instruments. However, they do not reflect the extent to which the
positions offset one another and consequently do not reflect our actual exposure
to market or credit risk.
Cash Flow Hedges - Our Energy Services and
ONEOK Partners segments use derivative instruments to hedge the cash flows
associated with anticipated purchases and sales of natural gas, NGLs and
condensate and cost of fuel used in the transportation of natural
gas. Accumulated other comprehensive income (loss) at June 30, 2010,
includes gains of approximately $28.8 million, net of tax, related to these
hedges that will be realized within the next 18 months as the forecasted
transactions affect earnings. If prices remain at current levels, we
will recognize $27.1 million in net gains over the next 12 months, and we will
recognize net gains of $1.7 million thereafter.
For the
six months ended June 30, 2010 and 2009, cost of sales and fuel in our
Consolidated Statements of Income includes $11.3 million in each period,
reflecting an adjustment to inventory at the lower of cost or market
value. In each period, we reclassified $11.3 million of deferred
gains, before income taxes, on associated cash flow hedges from accumulated
other comprehensive income (loss) into earnings.
The
following table sets forth the effect of cash flow hedges recognized in other
comprehensive income (loss) for the periods indicated:
Three
Months Ended
|
Six
Months Ended
|
||||||||||
Derivatives
in Cash Flow
Hedging
Relationships
|
June
30,
|
June
30,
|
|||||||||
2010
|
2009
|
2010
|
2009
|
||||||||
(Thousands
of dollars)
|
|||||||||||
Commodity
contracts
|
$ | 18,725 | $ | (32,363 | ) | $ | 81,053 | $ | 66,245 | ||
Interest
rate contracts
|
- | 443 | - | 564 | |||||||
Total
gain (loss) recognized in other
comprehensive
income (loss) on
derivatives
(effective portion)
|
$ | 18,725 | $ | (31,920 | ) | $ | 81,053 | $ | 66,809 | ||
21
The
following tables set forth the effect of cash flow hedges on our Consolidated
Statements of Income for the periods indicated:
Location
of Gain (Loss) Reclassified from
Accumulated
Other Comprehensive Income
(Loss)
into Net Income (Effective Portion)
|
Three
Months Ended
|
|||||||
Derivatives
in Cash Flow
Hedging
Relationships
|
June
30,
|
|||||||
2010
|
2009
|
|||||||
(Thousands
of dollars)
|
||||||||
Commodity
contracts
|
Revenues
|
$ | 5,490 | $ | 31,157 | |||
Commodity
contracts
|
Cost
of sales and fuel
|
(3,246 | ) | (9,624 | ) | |||
Interest
rate contracts
|
Interest
expense
|
221 | 436 | |||||
Total
gain (loss) reclassified from accumulated other comprehensive income
(loss)
into net income on derivatives (effective portion)
|
$ | 2,465 | $ | 21,969 | ||||
Location
of Gain (Loss) Reclassified from
Accumulated
Other Comprehensive Income
(Loss)
into Net Income (Effective Portion)
|
Six Months
Ended
|
|||||||
Derivatives
in Cash Flow
Hedging
Relationships
|
June
30,
|
|||||||
2010
|
2009
|
|||||||
(Thousands of dollars)
|
||||||||
Commodity
contracts
|
Revenues
|
$
|
35,446
|
$
|
113,872
|
|||
Commodity
contracts
|
Cost
of sales and fuel
|
(15,343
|
)
|
(11,178
|
)
|
|||
Interest
rate contracts
|
Interest
expense
|
442
|
872
|
|||||
Total
gain (loss) reclassified from accumulated other comprehensive
income
(loss)
into net income on derivatives (effective portion)
|
$
|
20,545
|
$
|
103,566
|
Location
of Gain (Loss) Recognized in Income
on
Derivatives (Ineffective Portion and Amount
Excluded
from Effectiveness Testing)
|
Three
Months Ended
|
|||||||
Derivatives
in Cash Flow
Hedging
Relationships
|
June
30,
|
|||||||
2010
|
2009
|
|||||||
(Thousands of dollars)
|
||||||||
Commodity
contracts
|
Revenues
|
$
|
98
|
$
|
(228
|
) | ||
Commodity
contracts
|
Cost
of sales and fuel
|
58
|
|
(217
|
)
|
|||
Total
gain (loss) reclassified from accumulated other comprehensive
income
(loss)
into net income on derivatives (effective portion)
|
$
|
156
|
$
|
(445
|
) |
Location
of Gain (Loss) Recognized in Income
on
Derivatives (Ineffective Portion and Amount
Excluded
from Effectiveness Testing)
|
Six
Months Ended
|
|||||||
Derivatives
in Cash Flow
Hedging
Relationships
|
June
30,
|
|||||||
2010
|
2009
|
|||||||
(Thousands of dollars)
|
||||||||
Commodity
contracts
|
Revenues
|
$
|
1,114
|
$
|
2,820
|
|||
Commodity
contracts
|
Cost
of sales and fuel
|
(819
|
)
|
(747
|
)
|
|||
Total
gain (loss) reclassified from accumulated other comprehensive
income
(loss)
into net income on derivatives (effective portion)
|
$
|
295
|
$
|
2,073
|
In the
event that it becomes probable that a forecasted transaction will not occur, we
will discontinue cash flow hedge treatment, which will affect
earnings. For the six months ended June 30, 2010 and 2009, there were
no gains or losses due to the discontinuance of cash flow hedge treatment since
the underlying transactions were no longer probable.
22
Other Derivative Instruments -
The following table sets forth the effect of our derivative instruments that are
not part of a hedging relationship on our Consolidated Statements of Income for
the periods indicated:
Three
Months Ended
|
Six
Months Ended
|
||||||||||||
Derivatives
Not Designated as
Hedging
Instruments
|
Location
of Gain
(Loss)
|
June
30,
|
June
30,
|
||||||||||
2010
|
2009
|
2010
|
2009
|
||||||||||
(Thousands
of dollars)
|
|||||||||||||
Commodity
contracts - trading
|
Revenues
|
$ | 1,358 | $ | 104 | $ | 3,386 | $ | 3,409 | ||||
Commodity
contracts - non-trading (a)
|
Cost
of gas and fuel
|
2,413 | 2,476 | 2,372 | 1,937 | ||||||||
Foreign
exchange contracts
|
Revenues
|
(69 | ) | 585 | (10 | ) | 323 | ||||||
Total
gain (loss) recognized in income on derivatives
|
$ | 3,702 | $ | 3,165 | $ | 5,748 | $ | 5,669 | |||||
(a)
- For the six months ended June 30, 2010 and 2009, we recognized $5.4
million and $2.1 million of losses associated with the fair value of
derivative instruments entered into by our Distribution segment that were
deferred as they are included in, and recoverable through, the monthly
purchased-gas cost mechanism. Recognized losses were immaterial for
the three months ended June 30, 2010 and 2009,
respectively.
|
|||||||||||||
Fair Value Hedges - In prior
years, we terminated various interest-rate swap agreements. The net
savings from the termination of these swaps is being recognized in interest
expense over the terms of the debt instruments originally
hedged. Interest expense savings from the amortization of terminated
swaps for the three months ended June 30, 2010 and 2009, were $2.5 million in
each period, and for the six months ended June 30, 2010 and 2009, were $5.0
million and $5.2 million, respectively. The remaining amortization of
terminated swaps will be recognized over the following periods:
ONEOK
|
||||||||||||
ONEOK
|
Partners
|
Total
|
||||||||||
(Millions
of dollars)
|
||||||||||||
Remainder
of 2010
|
$ | 3.2 | $ | 1.9 | $ | 5.1 | ||||||
2011
|
$ | 3.4 | $ | 0.9 | $ | 4.3 | ||||||
2012
|
$ | 1.7 | $ | - | $ | 1.7 | ||||||
2013
|
$ | 1.7 | $ | - | $ | 1.7 | ||||||
2014
|
$ | 1.7 | $ | - | $ | 1.7 | ||||||
Thereafter
|
$ | 23.6 | $ | - | $ | 23.6 |
ONEOK and
ONEOK Partners had no interest-rate swap agreements at June 30,
2010.
Our
Energy Services segment uses basis swaps to hedge the fair value of location
price differentials related to certain firm transportation
commitments. Net gains or losses from the fair value hedges and
ineffectiveness are recorded to cost of sales and fuel. The
ineffectiveness related to these hedges was not material for the three and six
months ended June 30, 2010 and 2009, respectively.
For the
three and six months ended June 30, 2010, cost of sales and fuel in our
Consolidated Statements of Income includes losses of $14.7 million and $3.9
million, respectively, related to the change in fair value of derivatives
declared as fair value hedges. Revenues include gains of $13.6
million and $4.0 million for the three and six months ended June 30, 2010,
respectively, to recognize the change in fair value of the hedged firm
commitments.
For the
three and six months ended June 30, 2009, cost of sales and fuel in our
Consolidated Statements of Income include gains of $46.6 million and $178.3
million, respectively, related to the change in fair value of derivatives
declared as fair value hedges. Revenues include losses of $46.6
million and $179.1 million for the three and six months ended June 30, 2009,
respectively, to recognize the change in fair value of the hedged firm
commitments.
Credit Risk - We monitor the
creditworthiness of our counterparties and compliance with policies and limits
established by our Risk Oversight and Strategy Committee. We maintain
credit policies with regard to our counterparties that we believe minimize
overall credit risk. These policies include an evaluation of
potential counterparties’ financial condition (including credit ratings, bond
yields and credit default swap rates), collateral requirements under certain
circumstances and the use of standardized master-netting agreements that allow
us to net the positive and negative exposures associated with a
single
23
counterparty. We
have counterparties whose credit is not rated, and for those customers we use
internally developed credit ratings.
Some of
our derivative instruments contain provisions that require us to maintain an
investment-grade credit rating from S&P and/or Moody’s. If our
credit ratings on senior unsecured long-term debt were to decline below
investment grade, we would be in violation of these provisions, and the
counterparties to the derivative instruments could request collateralization on
derivative instruments in net liability positions. The aggregate fair
value of all financial derivative instruments with contingent features related
to credit risk that were in a net liability position as of June 30, 2010, was
$6.1 million for which we have posted collateral of $3.1 million in the normal
course of business. If the contingent features underlying these
agreements were triggered on June 30, 2010, we would have been required to post
an additional $3.0 million of collateral to our counterparties.
The
counterparties to our derivative contracts consist primarily of major energy
companies, LDCs, electric utilities, financial institutions and commercial and
industrial end-users. This concentration of counterparties may impact
our overall exposure to credit risk, either positively or negatively, in that
the counterparties may be similarly affected by changes in economic, regulatory
or other conditions. Based on our policies, exposures, credit and
other reserves, we do not anticipate a material adverse effect on our financial
position or results of operations as a result of counterparty
nonperformance.
The
following table sets forth the net credit exposure from our derivative assets
for the periods indicated:
June
30, 2010
|
|||||||||||||
Investment
|
Non-investment
|
Not
|
|||||||||||
Grade
|
Grade
|
Rated
|
Total
|
||||||||||
Counterparty
sector
|
(Thousands
of dollars)
|
||||||||||||
Gas
and electric utilities
|
$ | 40,166 | $ | 1,665 | $ | 895 | $ | 42,726 | |||||
Oil
and gas
|
27,052 | - | 1,248 | 28,300 | |||||||||
Industrial
|
61 | - | 5,053 | 5,114 | |||||||||
Financial
|
31,716 | - | - | 31,716 | |||||||||
Other
|
- | 13 | - | 13 | |||||||||
Total
|
$ | 98,995 | $ | 1,678 | $ | 7,196 | $ | 107,869 |
December
31, 2009
|
|||||||||||||
Investment
|
Non-investment
|
Not
|
|||||||||||
Grade
|
Grade
|
Rated
|
Total
|
||||||||||
Counterparty
sector
|
(Thousands
of dollars)
|
||||||||||||
Gas
and electric utilities
|
$ | 26,964 | $ | 2,668 | $ | 7,972 | $ | 37,604 | |||||
Oil
and gas
|
54,578 | 224 | 10,084 | 64,886 | |||||||||
Industrial
|
689 | - | 3 | 692 | |||||||||
Financial
|
32,880 | - | 7 | 32,887 | |||||||||
Other
|
- | 55 | 40 | 95 | |||||||||
Total
|
$ | 115,111 | $ | 2,947 | $ | 18,106 | $ | 136,164 |
24
D. ACCUMULATED
OTHER COMPREHENSIVE INCOME (LOSS)
The
following table sets forth the balance in accumulated other comprehensive income
(loss) for the periods indicated:
Unrealized
Gains
(Losses)
on Energy
Marketing
and
Risk
Management
Assets/Liabilities
|
Unrealized
Holding
Gains
(Losses) on
Investment
Securities
|
Pension
and Postretirement
Benefit
Plan
Obligations
|
Accumulated
Other
Comprehensive
Income
(Loss)
|
|||||||||
(Thousands
of dollars)
|
||||||||||||
December
31, 2009
|
$ |
(6,151
|
) | $ |
1,441
|
$ |
(113,903
|
) | $ |
(118,613
|
) | |
Other
comprehensive income (loss)
attributable
to ONEOK
|
23,426
|
(267
|
) |
(8,032
|
) |
15,127
|
||||||
June
30, 2010
|
$ |
17,275
|
$ |
1,174
|
$ |
(121,935
|
) | $ |
(103,486
|
) |
E. CREDIT
FACILITIES AND SHORT-TERM NOTES PAYABLE
ONEOK Credit Agreement - Under
the ONEOK Credit Agreement, which expires July 2011, ONEOK is required to comply
with certain financial, operational and legal covenants. Among other
things, these requirements include:
·
|
a
$400 million sublimit for the issuance of standby letters of
credit;
|
·
|
a
limitation on ONEOK’s stand-alone debt-to-capital ratio, which may not
exceed 67.5 percent at the end of any calendar
quarter;
|
·
|
a
requirement that ONEOK maintain the power to control the management and
policies of ONEOK Partners; and
|
·
|
a
limit on new investments in master limited
partnerships.
|
The ONEOK
Credit Agreement also contains customary affirmative and negative covenants,
including covenants relating to liens, investments, fundamental changes in the
nature of ONEOK’s businesses, transactions with affiliates, the use of proceeds
and a covenant that prevents ONEOK from restricting its subsidiaries’ ability to
pay dividends.
The debt
covenant calculations in the ONEOK Credit Agreement exclude the debt of ONEOK
Partners. Upon breach of any covenant by ONEOK, amounts outstanding
under the ONEOK Credit Agreement may become immediately due and
payable. At June 30, 2010, ONEOK’s stand-alone debt-to-capital ratio,
as defined by the ONEOK Credit Agreement, was 38.2 percent, and ONEOK was in
compliance with all covenants under the ONEOK Credit Agreement.
At June
30, 2010, ONEOK had no commercial paper outstanding and $32.0 million in letters
of credit issued under the ONEOK Credit Agreement, leaving approximately $1.2
billion of credit available under the ONEOK Credit Agreement. At
December 31, 2009, ONEOK had $358.9 million in commercial paper outstanding and
$37.0 million in letters of credit issued under the ONEOK Credit
Agreement.
ONEOK Partners Credit
Agreement - Under the ONEOK Partners Credit Agreement, which expires
March 2012, ONEOK Partners is required to comply with certain financial,
operational and legal covenants. Among other things, these
requirements include maintaining a ratio of indebtedness to adjusted EBITDA
(EBITDA, as defined in the ONEOK Partners Credit Agreement, adjusted for all
non-cash charges and increased for projected EBITDA from certain lender-approved
capital expansion projects) of no more than 5 to 1. If ONEOK Partners
consummates one or more acquisitions in which the aggregate purchase price is
$25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will
be increased to 5.5 to 1 for the three calendar quarters following the
acquisitions. Upon breach of any covenant, discussed above, amounts
outstanding under the ONEOK Partners Credit Agreement may become immediately due
and payable. At June 30, 2010, ONEOK Partners’ ratio of indebtedness
to adjusted EBITDA was 4.3 to 1, and ONEOK Partners was in compliance with all
covenants under the ONEOK Partners Credit Agreement. Borrowings under
the ONEOK Partners Credit Agreement are nonrecourse to ONEOK.
In June
2010, ONEOK Partners initiated a commercial paper program under which ONEOK
Partners may issue unsecured commercial paper notes up to a maximum amount
outstanding of $1.0 billion to fund ONEOK Partners’ short-term borrowing
needs. The maturities of the commercial paper notes will vary but may
not exceed 270 days from the date of issue. The commercial paper
notes may be sold at a negotiated discount from par or will bear interest at a
negotiated rate.
25
The ONEOK
Partners Credit Agreement is available to repay the commercial paper notes, if
necessary. Amounts outstanding under ONEOK Partners’ commercial paper
program reduce the borrowing capacity under the ONEOK Partners Credit
Agreement. At June 30, 2010, ONEOK Partners had not issued any
commercial paper. In July 2010, ONEOK Partners
repaid all borrowings outstanding under the ONEOK Partners Credit Agreement with
proceeds from the issuance of commercial paper.
At June
30, 2010, and December 31, 2009, ONEOK Partners had $680 million and $523
million, respectively, in borrowings outstanding under the ONEOK Partners Credit
Agreement and $24.2 million issued in letters of credit outside of the ONEOK
Partners Credit Agreement. Under the most restrictive provisions of
the ONEOK Partners Credit Agreement, ONEOK Partners had $320 million of credit
available at June 30, 2010.
Borrowings
under the ONEOK Credit Agreement and the ONEOK Partners Credit Agreement are
typically short term in nature, ranging from one day to six months.
Accordingly, these borrowings are classified as short-term notes payable.
Neither
ONEOK nor ONEOK Partners guarantees the debt or other similar commitments to
unaffiliated parties, and ONEOK does not guarantee the debt or other similar
commitments of ONEOK Partners.
F. EQUITY
The
following table sets forth the changes in equity attributable to us and our
noncontrolling interests, including other comprehensive income, net of tax, for
the periods indicated:
Three
Months Ended
|
Three
Months Ended
|
|||||||||||||||||||||||
June
30, 2010
|
June
30, 2009
|
|||||||||||||||||||||||
ONEOK
Shareholders' Equity
|
Noncontrolling
Interests in Consolidated Subsidiaries
|
Total
Equity
|
ONEOK
Shareholders' Equity
|
Noncontrolling
Interests in Consolidated Subsidiaries
|
Total
Equity
|
|||||||||||||||||||
(Thousands
of dollars)
|
||||||||||||||||||||||||
Beginning
balance
|
$ | 2,380,697 | $ | 1,498,944 | $ | 3,879,641 | $ | 2,183,293 | $ | 1,057,840 | $ | 3,241,133 | ||||||||||||
Net
income
|
41,724 | 44,650 | 86,374 | 41,679 | 39,671 | 81,350 | ||||||||||||||||||
Other
comprehensive income (loss)
|
2,078 | 6,074 | 8,152 | (26,808 | ) | (14,940 | ) | (41,748 | ) | |||||||||||||||
Repurchase
of common stock
|
- | - | - | (3 | ) | - | (3 | ) | ||||||||||||||||
Common
stock issued
|
9,501 | - | 9,501 | 6,354 | - | 6,354 | ||||||||||||||||||
Common
stock dividends
|
(46,771 | ) | - | (46,771 | ) | (42,122 | ) | - | (42,122 | ) | ||||||||||||||
Issuance
of common units of ONEOK Partners
|
- | (17 | ) | (17 | ) | - | 220,458 | 220,458 | ||||||||||||||||
Distributions
to noncontrolling interests
|
- | (66,306 | ) | (66,306 | ) | - | (52,556 | ) | (52,556 | ) | ||||||||||||||
Ending
balance
|
$ | 2,387,229 | $ | 1,483,345 | $ | 3,870,574 | $ | 2,162,393 | $ | 1,250,473 | $ | 3,412,866 |
Six
Months Ended
|
Six
Months Ended
|
|||||||||||||||||||||||
June
30, 2010
|
June
30, 2009
|
|||||||||||||||||||||||
ONEOK
Shareholders' Equity
|
Noncontrolling
Interests in Consolidated Subsidiaries
|
Total
Equity
|
ONEOK
Shareholders' Equity
|
Noncontrolling
Interests in Consolidated Subsidiaries
|
Total
Equity
|
|||||||||||||||||||
(Thousands
of dollars)
|
||||||||||||||||||||||||
Beginning
balance
|
$ | 2,207,194 | $ | 1,238,268 | $ | 3,445,462 | $ | 2,088,170 | $ | 1,079,369 | $ | 3,167,539 | ||||||||||||
Net
income
|
196,263 | 76,831 | 273,094 | 163,964 | 80,935 | 244,899 | ||||||||||||||||||
Other
comprehensive income (loss)
|
15,127 | 22,361 | 37,488 | (12,344 | ) | (24,982 | ) | (37,326 | ) | |||||||||||||||
Repurchase
of common stock
|
(5 | ) | - | (5 | ) | (250 | ) | - | (250 | ) | ||||||||||||||
Common
stock issued
|
11,391 | - | 11,391 | 7,055 | - | 7,055 | ||||||||||||||||||
Common
stock dividends
|
(93,472 | ) | - | (93,472 | ) | (84,202 | ) | - | (84,202 | ) | ||||||||||||||
Issuance
of common units of ONEOK Partners
|
50,731 | 271,973 | 322,704 | - | 220,458 | 220,458 | ||||||||||||||||||
Distributions
to noncontrolling interests
|
- | (126,088 | ) | (126,088 | ) | - | (105,307 | ) | (105,307 | ) | ||||||||||||||
Ending
balance
|
$ | 2,387,229 | $ | 1,483,345 | $ | 3,870,574 | $ | 2,162,393 | $ | 1,250,473 | $ | 3,412,866 |
26
Dividends - Fourth-quarter
2009 and first-quarter 2010 dividends paid on our common stock to shareholders
of record at the close of business on January 30, 2010, and April 30, 2010, were
$0.44 per share. A second-quarter 2010 dividend of $0.46 per share
was declared for shareholders of record on July 30, 2010, payable on August 13,
2010.
See Note
L for a discussion of the issuance of common units of ONEOK Partners and
distributions to noncontrolling interests.
G. EMPLOYEE
BENEFIT PLANS
The
following table sets forth the components of net periodic benefit cost for our
pension and other postretirement benefit plans for the periods
indicated:
Pension
Benefits
|
Pension
Benefits
|
|||||||||||||||
Three
Months Ended
|
Six
Months Ended
|
|||||||||||||||
June
30,
|
June
30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(Thousands
of dollars)
|
||||||||||||||||
Components
of net periodic benefit cost
|
||||||||||||||||
Service
cost
|
$ | 4,819 | $ | 4,984 | $ | 9,638 | $ | 9,968 | ||||||||
Interest
cost
|
14,536 | 13,454 | 29,072 | 28,659 | ||||||||||||
Expected
return on assets
|
(18,413 | ) | (16,508 | ) | (36,826 | ) | (33,016 | ) | ||||||||
Amortization
of unrecognized prior service cost
|
320 | 391 | 640 | 782 | ||||||||||||
Amortization
of net loss
|
6,888 | 4,330 | 13,777 | 11,144 | ||||||||||||
Net
periodic benefit cost
|
$ | 8,150 | $ | 6,651 | $ | 16,301 | $ | 17,537 |
Postretirement
Benefits
|
Postretirement
Benefits
|
|||||||||||||||
Three
Months Ended
|
Six
Months Ended
|
|||||||||||||||
June
30,
|
June
30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(Thousands
of dollars)
|
||||||||||||||||
Components
of net periodic benefit cost
|
||||||||||||||||
Service
cost
|
$ | 1,232 | $ | 1,294 | $ | 2,463 | $ | 2,587 | ||||||||
Interest
cost
|
3,911 | 4,229 | 7,822 | 8,459 | ||||||||||||
Expected
return on assets
|
(1,974 | ) | (1,702 | ) | (3,948 | ) | (3,404 | ) | ||||||||
Amortization
of unrecognized net asset at adoption
|
798 | 797 | 1,595 | 1,594 | ||||||||||||
Amortization
of unrecognized prior service cost
|
(501 | ) | (501 | ) | (1,002 | ) | (1,002 | ) | ||||||||
Amortization
of net loss
|
1,752 | 2,415 | 3,504 | 4,830 | ||||||||||||
Net
periodic benefit cost
|
$ | 5,218 | $ | 6,532 | $ | 10,434 | $ | 13,064 |
Our
Distribution segment recovers certain pension benefit plan and other
postretirement benefit plan costs through rates charged to utility
customers. In September 2009, the KCC authorized us to defer the
difference between current GAAP pension and post-retirement expenses and the
level of these expenses incorporated in base rates as either a regulatory asset
or liability. Amortization and recovery of the accumulated deferrals will
begin with the effective date of our next rate change and will continue for a
period not to exceed five years. The impact from the KCC order was not
material for the six months ended June 30, 2010.
In March
2010, the Patient Protection and Affordable Care Act and the Health Care and
Education Reconciliation Act of 2010 (collectively, the Health Care Acts) were
signed into law. Based on our preliminary analysis of the Health Care
Acts, we do not expect a significant impact to our benefit plans or their
related costs. We do not participate in the federal retiree
prescription drug subsidy program, for which the tax treatment was changed as a
result of the Health Care Acts and, accordingly, are not impacted by the change
in tax treatment of the subsidy. With the exception of increasing our
dependent care age requirement to age 26 from age 24, our health plans provide
coverage levels that meet the near-term minimum requirements outlined in the
Health Care Acts. We continue to evaluate the implications of the
provisions of the Health Care Acts and expect to continue to provide benefit
plan options that meet the provisions outlined by the Health Care
Acts.
27
H. COMMITMENTS
AND CONTINGENCIES
Environmental Liabilities - We
are subject to multiple environmental, historical and wildlife preservation laws
and regulations affecting many aspects of our present and future
operations. Regulated activities include those involving air
emissions, stormwater and wastewater discharges, handling and disposal of solid
and hazardous wastes, hazardous materials transportation,
and pipeline and facility construction. These laws and regulations
require us to obtain and comply with a wide variety of environmental clearances,
registrations, licenses, permits and other approvals. Failure to
comply with these laws, regulations, permits and licenses may expose us to
fines, penalties and/or interruptions in our operations that could be material
to our results of operations. If a leak or spill of hazardous
substances or petroleum products occurs from pipelines or facilities that we
own, operate or otherwise use, we could be held jointly and severally liable for
all resulting liabilities, including response, investigation and clean up costs,
which could materially affect our results of operations and cash
flows. In addition, emission controls required under the Clean Air
Act and other similar federal and state laws could require unexpected capital
expenditures at our facilities. We cannot assure that existing
environmental regulations will not be revised or that new regulations will not
be adopted or become applicable to us. Revised or additional
regulations that result in increased compliance costs or additional operating
restrictions could have a material adverse effect on our business, financial
condition and results of operations.
We own or
retain legal responsibility for the environmental conditions at 12 former
manufactured gas sites in Kansas. These sites contain potentially
harmful materials that are subject to control or remediation under various
environmental laws and regulations. A consent agreement with the KDHE
presently governs all work at these sites. The terms of the consent
agreement allow us to investigate these sites and set remediation activities
based upon the results of the investigations and risk
analysis. Remediation typically involves the management of
contaminated soils and may involve removal of structures and monitoring and/or
remediation of groundwater.
Of the 12
sites, we have begun soil remediation on 11 sites. Regulatory closure
has been achieved at three locations, and we have completed or are near
completion of soil remediation at eight sites. We have begun site
assessment at the remaining site where no active remediation has
occurred.
Our
expenditures for environmental evaluation, mitigation, remediation and
compliance to date have not been significant in relation to our financial
position or results of operations, and our expenditures related to environmental
matters had no material effect upon earnings or cash flows during the three and
six months ended June 30, 2010 or 2009.
In May
2010, the EPA finalized the “Tailoring Rule” that will regulate greenhouse gas
emissions at new or modified facilities that meet certain
criteria. Affected facilities will be required to review best
available control technology, conduct air-quality analysis, impact analysis and
public reviews with respect to such emissions. The rule will be
phased in beginning January 2011 and, at current emission threshold levels, will
have a minimal impact on our existing facilities. The EPA has stated
it will consider lowering the threshold levels over the next five years, which
could increase the impact on our existing facilities. However,
potential costs, fees or expenses associated with the potential adjustments are
unknown.
In
addition, the EPA issued a rule on air-quality standards, “National Emission
Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion
Engines, also known as RICE NESHAP, scheduled to be adopted in early
2013. The rule will require capital expenditures over the next three
years for the purchase and installation of new emissions-control
equipment. We do not expect these expenditures to have a material
impact on our results of operations, financial position or cash
flows.
Legal Proceedings - We are a
party to various litigation matters and claims that have arisen in the normal
course of our operations. While the results of litigation and claims
cannot be predicted with certainty, we believe the final outcome of such matters
will not have a material adverse effect on our consolidated results of
operations, financial position or cash flows.
Overland Pass Pipeline Company
- Overland Pass Pipeline Company is a joint venture between ONEOK Partners and
Williams Partners L.P. (Williams). A subsidiary of ONEOK Partners
owns 99 percent of the joint venture and operates the pipeline. In
July 2010, ONEOK Partners received notification that Williams elected to
exercise its option to increase its ownership in Overland Pass Pipeline Company
to 50 percent from 1 percent. The purchase price, as determined in
accordance with the joint venture’s limited liability company agreement, is
estimated to be approximately $425 million. The transaction is expected to
be completed during the third quarter of 2010, subject to obtaining the
necessary regulatory approvals. Upon closing of the transaction and as
long as Williams owns at least 50 percent of Overland Pass Pipeline Company,
Williams will have the option to become operator. ONEOK Partners expects
to deconsolidate Overland Pass
28
Pipeline
Company and account for it under the equity method of accounting upon closing of
the transaction. ONEOK Partners does not expect the transaction to
have a material impact on its results of operations.
Investment in Northern Border
Pipeline - Northern Border Pipeline anticipates requiring an
additional equity contribution of approximately $102 million from its partners
in 2011, of which ONEOK Partners’ share will be approximately $51 million based
on its 50 percent equity interest.
I. SEGMENTS
Segment Descriptions - Our
operations are divided into three reportable business segments based on
similarities in economic characteristics, products and services, types of
customers, methods of distribution and regulatory environment. These
segments are as follows: (i) our ONEOK Partners segment gathers, processes,
transports, stores and sells natural gas and gathers, treats, fractionates,
stores, distributes and markets NGLs; (ii) our Distribution segment, which
includes our retail marketing operations, delivers natural gas to residential,
commercial, municipal and industrial customers and transports natural gas; and
(iii) our Energy Services segment markets natural gas to wholesale
customers. Our Distribution segment is comprised primarily of
regulated public utilities, and portions of our ONEOK Partners segment are also
regulated. Other and eliminations consists of the operating and
leasing operations of our headquarters building and related parking facility and
other amounts needed to reconcile our reportable segments to our consolidated
financial statements.
In the
first quarter of 2010, responsibility for our retail marketing business was
transferred to our Distribution segment from our Energy Services
segment. As a result, we have revised our reportable segments to
reflect this change in responsibility. Prior-period amounts have been
recast to reflect this transfer.
Accounting Policies - The
accounting policies of the segments are the same as those described in Note A of
the Notes to Consolidated Financial Statements in our Annual
Report. Intersegment sales are recorded on the same basis as sales to
unaffiliated customers and are discussed in further detail in Note
L. Net margin is comprised of total revenues less cost of sales and
fuel. Cost of sales and fuel includes commodity purchases, fuel,
storage and transportation costs.
Customers - For the three and
six months ended June 30, 2010 and 2009, we had no single external customer from
which we received 10 percent or more of our consolidated revenues.
Operating Segment Information
- The following tables set forth certain selected financial information for our
operating segments for the periods indicated:
June
30, 2010
|
ONEOK
Partners
(a)
|
Distribution
(b)
|
Energy
Services
|
Other
and Eliminations
|
Total
|
||||||||||||||
(Thousands
of dollars)
|
|||||||||||||||||||
Sales
to unaffiliated customers
|
$ | 1,947,032 | $ | 338,476 | $ | 520,856 | $ | 767 | $ | 2,807,131 | |||||||||
Intersegment
revenues
|
108,089 | 3,757 | 134,885 | (246,731 | ) | - | |||||||||||||
Total
revenues
|
$ | 2,055,121 | $ | 342,233 | $ | 655,741 | $ | (245,964 | ) | $ | 2,807,131 | ||||||||
Net
margin
|
$ | 288,162 | $ | 161,481 | $ | 7,669 | $ | 765 | $ | 458,077 | |||||||||
Operating
costs
|
97,958 | 98,245 | 6,544 | 834 | 203,581 | ||||||||||||||
Depreciation
and amortization
|
43,987 | 30,877 | 193 | 453 | 75,510 | ||||||||||||||
Gain
(loss) on sale of assets
|
(260 | ) | (13 | ) | - | - | (273 | ) | |||||||||||
Operating
income
|
$ | 145,957 | $ | 32,346 | $ | 932 | $ | (522 | ) | $ | 178,713 | ||||||||
Equity
earnings from investments
|
$ | 20,676 | $ | - | $ | - | $ | - | $ | 20,676 | |||||||||
Capital
expenditures
|
$ | 62,867 | $ | 46,947 | $ | - | $ | 1,617 | $ | 111,431 | |||||||||
(a)
- Our ONEOK Partners segment has regulated and non-regulated
operations. Our ONEOK Partners segment's regulated operations had
revenues of $151.9 million, net margin of $126.5 million and operating
income of $66.9 million.
|
|||||||||||||||||||
(b)
- Our Distribution segment has regulated and non-regulated
operations. Our Distribution segment's regulated operations had
revenues of $275.8 million, net margin of $159.0 million and operating
income of $31.9 million.
|
29
Three
Months Ended
June
30, 2009
|
ONEOK
Partners
(a)
|
Distribution
(b)
|
Energy
Services
|
Other
and Eliminations
|
Total
|
||||||||||||||
(Thousands
of dollars)
|
|||||||||||||||||||
Sales
to unaffiliated customers
|
$ | 1,289,487 | $ | 329,069 | $ | 608,300 | $ | 771 | $ | 2,227,627 | |||||||||
Intersegment
revenues
|
107,570 | 1,764 | 113,865 | (223,199 | ) | - | |||||||||||||
Total
revenues
|
$ | 1,397,057 | $ | 330,833 | $ | 722,165 | $ | (222,428 | ) | $ | 2,227,627 | ||||||||
Net
margin
|
$ | 261,982 | $ | 146,403 | $ | 23,274 | $ | 767 | $ | 432,426 | |||||||||
Operating
costs
|
100,507 | 101,149 | 8,848 | (369 | ) | 210,135 | |||||||||||||
Depreciation
and amortization
|
39,953 | 30,733 | 130 | 433 | 71,249 | ||||||||||||||
Gain
(loss) on sale of assets
|
3,276 | 486 | - | - | 3,762 | ||||||||||||||
Operating
income
|
$ | 124,798 | $ | 15,007 | $ | 14,296 | $ | 703 | $ | 154,804 | |||||||||
Equity
earnings from investments
|
$ | 14,188 | $ | - | $ | - | $ | - | $ | 14,188 | |||||||||
Capital
expenditures
|
$ | 129,366 | $ | 32,632 | $ | - | $ | 2,575 | $ | 164,573 | |||||||||
(a)
- Our ONEOK Partners segment has regulated and non-regulated
operations. Our ONEOK Partners segment's regulated operations had
revenues of $117.8 million, net margin of $97.8 million and operating
income of $41.5 million.
|
|||||||||||||||||||
(b)
- Our Distribution segment has regulated and non-regulated
operations. Our Distribution segment's regulated operations had
revenues of $276.5 million, net margin of $139.6 million and operating
income of $9.9 million.
|
Six
Months Ended
June
30, 2010
|
ONEOK
Partners
(a)
|
Distribution
(b)
|
Energy
Services
|
Other
and Eliminations
|
Total
|
||||||||||||||
(Thousands
of dollars)
|
|||||||||||||||||||
Sales
to unaffiliated customers
|
$ | 4,014,107 | $ | 1,336,384 | $ | 1,379,089 | $ | 1,518 | $ | 6,731,098 | |||||||||
Intersegment
revenues
|
245,020 | 7,248 | 470,487 | (722,755 | ) | - | |||||||||||||
Total
revenues
|
$ | 4,259,127 | $ | 1,343,632 | $ | 1,849,576 | $ | (721,237 | ) | $ | 6,731,098 | ||||||||
Net
margin
|
$ | 549,287 | $ | 408,307 | $ | 118,288 | $ | 1,515 | $ | 1,077,397 | |||||||||
Operating
costs
|
194,266 | 198,021 | 13,971 | 668 | 406,926 | ||||||||||||||
Depreciation
and amortization
|
87,857 | 64,222 | 346 | 942 | 153,367 | ||||||||||||||
Gain
(loss) on sale of assets
|
(1,045 | ) | (13 | ) | - | - | (1,058 | ) | |||||||||||
Operating
income
|
$ | 266,119 | $ | 146,051 | $ | 103,971 | $ | (95 | ) | $ | 516,046 | ||||||||
Equity
earnings from investments
|
$ | 41,792 | $ | - | $ | - | $ | - | $ | 41,792 | |||||||||
Investments
in unconsolidated
affiliates
|
$ | 757,232 | $ | - | $ | - | $ | - | $ | 757,232 | |||||||||
Total
assets
|
$ | 7,780,642 | $ | 2,951,755 | $ | 627,190 | $ | 760,324 | $ | 12,119,911 | |||||||||
Noncontrolling
interests in
consolidated
subsidiaries
|
$ | 5,276 | $ | - | $ | - | $ | 1,478,069 | $ | 1,483,345 | |||||||||
Capital
expenditures
|
$ | 98,694 | $ | 78,325 | $ | 52 | $ | 2,633 | $ | 179,704 | |||||||||
(a)
- Our ONEOK Partners segment has regulated and non-regulated
operations. Our ONEOK Partners segment's regulated operations had
revenues of $303.9 million, net margin of $252.2 million and operating
income of $36.2 million.
|
|||||||||||||||||||
(b)
- Our Distribution segment has regulated and non-regulated
operations. Our Distribution segment's regulated operations had
revenues of $1,133.4 million, net margin of $401.6 million and operating
income of $143.2 million.
|
30
Six
Months Ended
June
30, 2009
|
ONEOK
Partners
(a)
|
Distribution
(b)
|
Energy
Services
|
Other
and Eliminations
|
Total
|
||||||||||||||
(Thousands
of dollars)
|
|||||||||||||||||||
Sales
to unaffiliated customers
|
$ | 2,396,217 | $ | 1,178,423 | $ | 1,441,284 | $ | 1,530 | $ | 5,017,454 | |||||||||
Intersegment
revenues
|
251,705 | 4,074 | 402,950 | (658,729 | ) | - | |||||||||||||
Total
revenues
|
$ | 2,647,922 | $ | 1,182,497 | $ | 1,844,234 | $ | (657,199 | ) | $ | 5,017,454 | ||||||||
Net
margin
|
$ | 515,523 | $ | 385,356 | $ | 81,448 | $ | 1,510 | $ | 983,837 | |||||||||
Operating
costs
|
189,953 | 192,587 | 14,994 | (453 | ) | 397,081 | |||||||||||||
Depreciation
and amortization
|
79,893 | 62,359 | 261 | 862 | 143,375 | ||||||||||||||
Gain
(loss) on sale of assets
|
3,940 | 486 | - | - | 4,426 | ||||||||||||||
Operating
income
|
$ | 249,617 | $ | 130,896 | $ | 66,193 | $ | 1,101 | $ | 447,807 | |||||||||
Equity
earnings from investments
|
$ | 35,410 | $ | - | $ | - | $ | - | $ | 35,410 | |||||||||
Capital
expenditures
|
$ | 321,860 | $ | 77,284 | $ | - | $ | 8,456 | $ | 407,600 | |||||||||
(a)
- Our ONEOK Partners segment has regulated and non-regulated
operations. Our ONEOK Partners segment's regulated operations had
revenues of $237.2 million, net margin of $193.3 million and operating
income of $86.8 million.
|
|||||||||||||||||||
(b)
- Our Distribution segment has regulated and non-regulated
operations. Our Distribution segment's regulated operations had
revenues of $1,026.4 million, net margin of $374.1 million and operating
income of $122.7 million.
|
J. UNCONSOLIDATED
AFFILIATES
Equity Earnings from
Investments - The following table sets forth our equity earnings from
investments for the periods indicated. All amounts in the table below
are equity earnings from investments in our ONEOK Partners segment:
Three
Months Ended
|
Six
Months Ended
|
|||||||||||||||
June
30,
|
June
30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(Thousands
of dollars)
|
||||||||||||||||
Northern
Border Pipeline
|
$ | 12,372 | $ | 5,454 | $ | 27,218 | $ | 21,492 | ||||||||
Bighorn
Gas Gathering, L.L.C.
|
1,811 | 1,824 | 2,048 | 3,910 | ||||||||||||
Fort
Union Gas Gathering, L.L.C.
|
3,581 | 3,805 | 7,139 | 6,015 | ||||||||||||
Lost
Creek Gathering Company, L.L.C.
|
1,454 | 1,312 | 2,856 | 2,202 | ||||||||||||
Other
|
1,458 | 1,793 | 2,531 | 1,791 | ||||||||||||
Equity
earnings from investments
|
$ | 20,676 | $ | 14,188 | $ | 41,792 | $ | 35,410 |
Unconsolidated Affiliates Financial
Information - The following table sets forth summarized combined
financial information of our unconsolidated affiliates for the periods
indicated:
Three
Months Ended
|
Six
Months Ended
|
|||||||||||||||
June
30,
|
June
30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(Thousands
of dollars)
|
||||||||||||||||
Income
Statement
|
||||||||||||||||
Operating
revenues
|
$ | 98,077 | $ | 87,951 | $ | 197,308 | $ | 194,017 | ||||||||
Operating
expenses
|
$ | 44,896 | $ | 44,429 | $ | 89,611 | $ | 89,232 | ||||||||
Net
income
|
$ | 45,955 | $ | 32,129 | $ | 92,866 | $ | 82,645 | ||||||||
Distributions
paid to us
|
$ | 26,115 | $ | 30,142 | $ | 49,644 | $ | 63,473 |
31
Distributions
paid to us are classified as operating activities on our Consolidated Statements
of Cash Flows until the cumulative distributions exceed our proportionate share
of income from the unconsolidated affiliate since the date of our initial
investment. The amount of cumulative distributions paid to us that
exceeds our cumulative proportionate share of income in each period represents a
return of investment and is classified as an investing activity on our
Consolidated Statements of Cash Flows. Distributions paid to us
includes a $9.1 million and $17.1 million return of investment for the three
months ended June 30, 2010 and 2009, respectively, and $10.6 million and $25.2
million for the six months ended June 30, 2010 and 2009,
respectively.
K. EARNINGS
PER SHARE INFORMATION
The
following tables set forth the computations of basic and diluted EPS from
continuing operations for the periods indicated:
Three
Months Ended June 30, 2010
|
||||||||||||
Per
Share
|
||||||||||||
Income
|
Shares
|
Amount
|
||||||||||
(Thousands,
except per share amounts)
|
||||||||||||
Basic
EPS from continuing operations
|
||||||||||||
Net
income attributable to ONEOK available for common stock
|
$ | 41,724 | 106,356 | $ | 0.39 | |||||||
Diluted
EPS from continuing operations
|
||||||||||||
Effect
of options and other dilutive securities
|
- | 1,482 | ||||||||||
Net
income attributable to ONEOK available for common stock
|
||||||||||||
and common stock equivalents | $ | 41,724 | 107,838 | $ | 0.39 |
Three
Months Ended June 30, 2009
|
||||||||||||
Per
Share
|
||||||||||||
Income
|
Shares
|
Amount
|
||||||||||
(Thousands,
except per share amounts)
|
||||||||||||
Basic
EPS from continuing operations
|
||||||||||||
Net
income attributable to ONEOK available for common stock
|
$ | 41,679 | 105,335 | $ | 0.40 | |||||||
Diluted
EPS from continuing operations
|
||||||||||||
Effect
of options and other dilutive securities
|
- | 615 | ||||||||||
Net
income attributable to ONEOK available for common stock
|
||||||||||||
and common stock equivalents | $ | 41,679 | 105,950 | $ | 0.39 |
Six
Months Ended June 30, 2010
|
||||||||||||
Per
Share
|
||||||||||||
Income
|
Shares
|
Amount
|
||||||||||
(Thousands,
except per share amounts)
|
||||||||||||
Basic
EPS from continuing operations
|
||||||||||||
Net
income attributable to ONEOK available for common stock
|
$ | 196,263 | 106,244 | $ | 1.85 | |||||||
Diluted
EPS from continuing operations
|
||||||||||||
Effect
of options and other dilutive securities
|
- | 1,380 | ||||||||||
Net
income attributable to ONEOK available for common stock
|
||||||||||||
and common stock equivalents | $ | 196,263 | $ | 107,624 | $ | 1.82 |
32
Six
Months Ended June 30, 2009
|
||||||||||||
Per
Share
|
||||||||||||
Income
|
Shares
|
Amount
|
||||||||||
(Thousands,
except per share amounts)
|
||||||||||||
Basic
EPS from continuing operations
|
||||||||||||
Net
income attributable to ONEOK available for common stock
|
$ | 163,964 | 105,249 | $ | 1.56 | |||||||
Diluted
EPS from continuing operations
|
||||||||||||
Effect
of options and other dilutive securities
|
- | 599 | ||||||||||
Net
income attributable to ONEOK available for common stock
|
||||||||||||
and common stock equivalents | $ | 163,964 | 105,848 | $ | 1.55 |
There
were no option shares excluded from the calculation of diluted EPS for the six
months ended June 30, 2010, and 261,634 option shares excluded from the
calculation of diluted EPS for the six months ended June 30, 2009.
L. ONEOK
PARTNERS
Ownership Interest in ONEOK
Partners - Our ownership interest in ONEOK Partners is shown in the
following table for the periods indicated.
June
30,
|
December
31,
|
|||
2010
|
2009
|
|||
General
partner interest
|
2.0%
|
2.0%
|
||
Limited
partner interest (a)
|
40.8%
|
43.1%
|
||
Total
ownership interest
|
42.8%
|
45.1%
|
||
(a)
- Represents 5.9 million common units and approximately 36.5 million Class
B units, which are convertible, at our option, into common
units.
|
In
February 2010, ONEOK Partners completed an underwritten public offering of
5,500,900 common units, including the partial exercise by the underwriters of
their over-allotment option, at a public offering price of $60.75 per common
unit, generating net proceeds of approximately $322.7 million. In
conjunction with the offering, ONEOK Partners GP contributed $6.8 million in
order to maintain its 2 percent general partner interest. ONEOK
Partners used the proceeds from the sale of common units and the general partner
contribution to repay borrowings under the ONEOK Partners Credit Agreement and
for general partnership purposes.
We
account for the difference between the carrying amount of our investment in
ONEOK Partners and the underlying book value arising from issuance of common
units by ONEOK Partners as an equity transaction. If ONEOK Partners
issues common units at a price different than our carrying value per unit, we
account for the premium or deficiency as an adjustment to paid-in
capital. As a result of ONEOK Partners’ issuance of common units at a
premium to our carrying value per unit, we recognized an increase to paid-in
capital of $50.7 million during the six months ended June 30, 2010.
Cash Distributions - The
following table sets forth ONEOK Partners’ general partner and incentive
distributions declared for the periods indicated:
Three
Months Ended
|
Six
Months Ended
|
|||||||||||
June
30,
|
June
30,
|
|||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||
(Thousands
of dollars)
|
||||||||||||
General
partner distributions
|
$ | 2,874 | $ | 2,551 | $ | 5,707 | $ | 4,970 | ||||
Incentive
distributions
|
26,689 | 21,437 | 52,399 | 41,757 | ||||||||
Total
distributions to general partner
|
$ | 29,563 | $ | 23,988 | $ | 58,106 | $ | 46,727 |
The
quarterly distributions paid by ONEOK Partners to limited partners in the first
and second quarters of 2010 were $1.10 per unit and $1.11 per unit,
respectively. The quarterly distributions paid by ONEOK Partners to
limited partners in each of the first and second quarters of 2009 were $1.08 per
unit.
33
For the
three months ended June 30, 2010 and 2009, cash distributions paid to us totaled
$75.6 million and $68.5 million, respectively. For the six months
ended June 30, 2010 and 2009, cash distributions paid by ONEOK Partners to us
totaled $148.3 million and $137.0 million, respectively.
In July
2010, a cash distribution from ONEOK Partners of $1.12 per unit payable in the
third quarter was declared. On August 31, 2010, we will receive the
related incentive distribution of $26.7 million for the second quarter of 2010,
which is included in the table above.
Relationship - We consolidate
ONEOK Partners in our consolidated financial statements; however, we are
restricted from the assets and cash flows of ONEOK Partners except for our
distributions. Distributions are declared quarterly by ONEOK
Partners’ general partner based on the terms of the ONEOK Partners partnership
agreement. See Note I for more information on ONEOK Partners’
results.
Affiliate Transactions - We
have certain transactions with our ONEOK Partners affiliate and its
subsidiaries, which comprise our ONEOK Partners segment.
ONEOK
Partners sells natural gas from its natural gas gathering and processing
operations to our Energy Services segment. In addition, a portion of
ONEOK Partners’ revenues from its natural gas pipelines business is from our
Energy Services and Distribution segments, which contract with ONEOK Partners
for natural gas transportation and storage services. ONEOK Partners
also purchases natural gas from our Energy Services segment for its natural gas
liquids and natural gas gathering and processing operations.
ONEOK
Partners has certain contractual rights to our Bushton Plant through a
Processing and Services Agreement with us, which sets out the terms for
processing and related services we provide at the Bushton Plant through
2012. ONEOK Partners has contracted for all of the capacity of the
Bushton Plant from our wholly owned subsidiary, OBPI. In exchange,
ONEOK Partners pays OBPI for all costs and expenses necessary for the operation
and maintenance of the Bushton Plant, and reimburses us for our obligations
under equipment leases covering the Bushton Plant.
We
provide a variety of services to our affiliates, including cash management and
financial services, administrative services provided by our employees and
management, insurance and office space leased in our headquarters building and
other field locations. Where costs are specifically incurred on
behalf of an affiliate, the costs are billed directly to the affiliate by
us. In other situations, the costs may be allocated to the affiliates
through a variety of methods, depending upon the nature of the expenses and the
activities of the affiliates. For example, a service that applies
equally to all employees is allocated based upon the
number of employees in each affiliate. However, an expense benefiting
the consolidated company but having no direct basis for allocation is allocated
by the modified Distrigas method, a method using a combination of ratios that
includes gross plant and investment, earnings before interest and taxes and
payroll expense. It is not practicable to determine what these
general overhead costs would be on a stand-alone basis.
The
following table sets forth transactions with ONEOK Partners, which have been
eliminated in consolidation for the periods indicated:
Three
Months Ended
|
Six
Months Ended
|
||||||||||||
June
30,
|
June
30,
|
||||||||||||
2010
|
2009
|
2010
|
2009
|
||||||||||
(Thousands
of dollars)
|
|||||||||||||
Revenues
|
$ | 108,089 | $ | 107,570 | $ | 245,020 | $ | 251,705 | |||||
Expenses
|
|||||||||||||
Cost
of sales and fuel
|
$ | 11,215 | $ | 9,416 | $ | 28,974 | $ | 26,054 | |||||
Administrative
and general expenses
|
51,974 | 49,855 | 102,999 | 98,478 | |||||||||
Total
expenses
|
$ | 63,189 | $ | 59,271 | $ | 131,973 | $ | 124,532 |
34
ITEM
2.
|
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
The
following discussion and analysis should be read in conjunction with our
unaudited consolidated financial statements and the Notes to Consolidated
Financial Statements in this Quarterly Report, as well as our Annual
Report. Due to the seasonal nature of our business, the results of
operations for the three and six months ended June 30, 2010, are not necessarily
indicative of the results that may be expected for a 12-month
period.
EXECUTIVE
SUMMARY
Outlook - We expect a slow
economic recovery to continue for the remainder of 2010. Although
volatility in the financial markets could limit our access to financial markets
on a timely basis or increase our cost of capital in the future, we anticipate
improved credit markets for the remainder of 2010, compared with 2009; however,
the potential impacts of the recently enacted Dodd-Frank Wall Street Reform and
Consumer Protection Act (Dodd-Frank Act) may reduce liquidity in the financial
markets and could increase our cost of capital and the costs of hedging certain
risks inherent in our business. We anticipate the consolidation of
underperforming assets in the industry, particularly those with high commodity
price exposure and/or high levels of debt. Additionally, we
anticipate an improving commodity price environment to continue during 2010,
compared with 2009.
Growth Projects - In
April 2010, ONEOK Partners announced that it will invest approximately $405
million to $470 million for projects in the Bakken Shale in the Williston Basin
in North Dakota and in the Woodford Shale in Oklahoma, which will enable ONEOK
Partners to meet the rapidly growing needs of producers in these
areas.
Garden Creek plant and
related projects - ONEOK Partners plans to construct a new
100 MMcf/d natural gas processing facility, the Garden Creek plant, in eastern
McKenzie County, North Dakota. The plant and related expansions are
estimated to cost between $150 million and $210 million and will double ONEOK
Partners’ natural gas processing capacity in the Williston
Basin. These projects are expected to be completed in the fourth
quarter of 2011. In addition, ONEOK Partners will invest an
additional $200 million to $205 million during 2010 and 2011 for new well
connections, expansions and upgrades to its existing natural gas gathering
infrastructure in the Bakken Shale.
Woodford Shale
projects - ONEOK Partners will also invest $55 million in the Woodford
Shale in Oklahoma for new well connections in 2010 and 2011 and to connect its
natural gas gathering system to its Maysville, Oklahoma, natural gas processing
facility, as well as for the connection of a new third-party processing plant to
ONEOK Partners’ NGL gathering system in Oklahoma.
Bakken Pipeline and related
projects - In July 2010, ONEOK Partners announced plans to build a 525-
to 615-mile NGL pipeline that will transport unfractionated NGLs from the Bakken
Shale in the Williston Basin in North Dakota to the Overland Pass
Pipeline. The Bakken Pipeline will initially transport up to 60
MBbl/d of unfractionated NGL production from ONEOK Partners’ natural gas
gathering and processing assets in the Bakken Shale and from third-party natural
gas processing plants south through western North Dakota and eastern Montana to
Wyoming, where it will connect to the Overland Pass Pipeline near Cheyenne,
Wyoming. The volumes will then be delivered to ONEOK Partners’
existing NGL infrastructure in the Mid-Continent. Additional pump facilities
could increase the new pipeline’s capacity to 110 MBbl/d. Supply
commitments for the Bakken Pipeline will be anchored by NGL production from
ONEOK Partners’ natural gas processing plants and from third-party processors,
which are in various stages of negotiation. Following receipt of all
necessary permits, construction of the 12-inch diameter pipeline is expected to
begin in the second quarter of 2012 and is currently expected to be completed
during the first half of 2013. Project costs for the new pipeline are
estimated to be $450 million to $550 million.
The
additional unfractionated NGL volumes from the new Bakken Pipeline will require
an investment of $35 million to $40 million for ONEOK Partners’ anticipated
share of the costs for additional pump stations and the expansion of existing
pump stations on the Overland Pass Pipeline. This investment along with
projected capital expenditures in 2010, will increase capacity to the maximum of
255 MBbl/d.
ONEOK
Partners also will invest $110 million to $140 million to expand and upgrade its
existing fractionation capacity at Bushton, Kansas, increasing its capacity up
to 210 MBbl/d from 150 MBbl/d.
Sterling I Pipeline
Expansion - In July 2010, ONEOK Partners announced plans to install seven
additional pump stations for approximately $36 million along its existing
Sterling I natural gas liquids distribution pipeline, increasing its capacity by
15
35
MBbl/d,
which will be supplied by ONEOK Partners’ Mid-Continent NGL
infrastructure. The Sterling I pipeline transports NGL
products from ONEOK Partners’ fractionator in Medford, Oklahoma, to the Mont
Belvieu, Texas, market center and is currently operating at
capacity. The pump station installation will begin later this
year and is expected to be completed in the second half of 2011.
Operating Results - Diluted
earnings per share of common stock (EPS) was $0.39 for the three months ended
June 30, 2010 and 2009, respectively. For the six-month period, EPS
increased to $1.82 from $1.55 for the same period last
year. Operating income for the three months ended June 30, 2010,
increased to $178.7 million from $154.8 million for the same period last
year. For the six months ended June 30, 2010, operating income
increased to $516.0 million from $447.8 million for the same period last
year. The increase in operating income is due primarily to the
following:
·
|
increased
net margin in our Energy Services segment, due primarily to higher
realized storage differentials and marketing margins, net of hedging
activities, offset partially by decreased premium-services
margins;
|
·
|
increased
net margin in our ONEOK Partners segment, due primarily to the
following:
|
-
|
higher
NGL volumes gathered, fractionated and transported, associated with the
completion of ONEOK Partners’ capital projects, as well as new NGL supply
connections, offset partially by lower optimization margins as increasing
NGL volumes from customers under fee-based contracts limited the
fractionation and transportation capacity available for optimization
activities;
|
-
|
increased
natural gas transportation capacity contracted and the impact of higher
natural gas prices on retained fuel;
and
|
·
|
increased
net margin in our Distribution segment, due primarily to new rates in
Oklahoma, which have a rate design that lowers our volumetric
sensitivity.
|
ONEOK Partners’ Equity
Issuance - In February 2010, ONEOK Partners completed an underwritten
public offering of 5,500,900 common units, including the partial exercise by the
underwriters of their over-allotment option, at a public offering price of
$60.75 per common unit, generating net proceeds of approximately $322.7
million. In conjunction with the offering, ONEOK Partners GP contributed
$6.8 million in order to maintain its 2 percent general partner interest.
ONEOK Partners used the proceeds from the sale of common units and the general
partner contribution to repay borrowings under the ONEOK Partners Credit
Agreement and for general partnership purposes. We currently hold a 42.8
percent aggregate equity interest in ONEOK Partners.
ONEOK Partners’ Commercial Paper
Program - In June 2010, ONEOK Partners established a commercial paper
program providing for the issuance of up to $1.0 billion of unsecured commercial
paper notes. Amounts outstanding under the commercial paper program
reduce the borrowings available under the ONEOK Partners Credit
Agreement. At June 30, 2010, ONEOK Partners had not issued any
commercial paper. In July 2010, ONEOK Partners repaid all borrowings
outstanding under the ONEOK Partners Credit Agreement with proceeds from the
issuance of commercial paper.
Long-term Debt - In June 2010,
ONEOK Partners repaid $250 million of maturing senior notes with available cash
and short-term borrowings. With the repayment of these notes, ONEOK
Partners no longer has any obligation to offer to repurchase the $225 million
senior notes due 2011 in the event that ONEOK Partners’ long-term debt credit
ratings fall below investment grade.
Overland Pass Pipeline Company
- Overland Pass Pipeline Company is a joint venture between ONEOK Partners and
Williams Partners L.P. (Williams). A subsidiary of ONEOK Partners owns 99
percent of the joint venture and operates the pipeline. In July 2010,
ONEOK Partners received notification that Williams elected to exercise its
option to increase its ownership in Overland Pass Pipeline Company to 50 percent
from 1 percent. The purchase price, as determined in accordance with the
joint venture’s limited liability company agreement, is estimated to be
approximately $425 million. The transaction is expected to be completed
during the third quarter of 2010, subject to obtaining the necessary regulatory
approvals. Upon closing of the transaction and as long as Williams owns at
least 50 percent of Overland Pass Pipeline Company, Williams will have the
option to become operator. ONEOK Partners does not expect the transaction
to have a material impact on its results of operations. ONEOK
Partners expects to use the proceeds from the transaction to repay short-term
debt and to fund its recently announced capital projects.
Dividends/Distributions - We
declared a quarterly dividend of $0.46 per share ($1.84 per share on an
annualized basis) in July 2010, an increase of 10 percent from the $0.42 per
share declared in July 2009. ONEOK Partners declared a cash
distribution of $1.12 per unit ($4.48 per unit on an annualized basis) in July
2010, an increase of approximately 4 percent from the $1.08 per unit declared in
July 2009.
36
Retail Marketing - In the
first quarter of 2010, responsibility for our retail marketing business was
transferred to our Distribution segment from our Energy Services
segment. This transfer enables our Energy Services segment to
increase its
focus on providing premium services to its wholesale customers. As a result, we
have revised our reportable segments to reflect this change in responsibility.
Prior-period amounts have been recast to reflect this transfer.
Environmental Liabilities
- We are
subject to multiple environmental, historical and wildlife preservation laws and
regulations affecting many aspects of our present and future
operations. Regulated activities include those involving air
emissions, stormwater and wastewater discharges, handling and disposal of solid
and hazardous wastes, hazardous materials transportation, and pipeline and
facility construction. These laws and regulations require us to
obtain and comply with a wide variety of environmental clearances,
registrations, licenses, permits and other approvals. Failure to
comply with these laws, regulations, permits and licenses may expose us to
fines, penalties and/or interruptions in our operations that could be material
to our results of operations. If a leak or spill of hazardous
substances or petroleum products occurs from pipelines or facilities that we
own, operate or otherwise use, we could be held jointly and severally liable for
all resulting liabilities, including response, investigation and clean-up costs,
which could materially affect our results of operations and cash
flows. In addition, emission controls required under the Clean Air
Act and other similar federal and state laws could require unexpected capital
expenditures at our facilities. We cannot assure that existing
environmental regulations will not be revised or that new regulations will not
be adopted or become applicable to us. Revised or additional
regulations that result in increased compliance costs or additional operating
restrictions could have a material adverse effect on our business, financial
condition and results of operations.
In May
2010, the EPA finalized the “Tailoring Rule” that will regulate greenhouse gas
emissions at new or modified facilities that meet certain
criteria. Affected facilities will be required to review best
available control technology, conduct air-quality analysis, impact analysis and
public reviews with respect to such emissions. The rule will be
phased in beginning January 2011 and, at current emission threshold levels, will
have a minimal impact on our existing facilities. The EPA has stated
it will consider lowering the threshold levels over the next five years, which
could increase the impact on our existing facilities. However,
potential costs, fees or expenses associated with the potential adjustments are
unknown.
In
addition, the EPA issued a rule on air-quality standards, “National Emission
Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion
Engines,” also known as RICE NESHAP, scheduled to be adopted in early
2013. The rule will require capital expenditures over the next three
years for the purchase and installation of new emissions-control
equipment. We do not expect these expenditures to have a material impact
on our results of operations, financial position or cash flows.
Financial Markets Legislation
- In July 2010, the
Dodd-Frank Act was enacted, representing a far-reaching overhaul of the
framework for regulation of U.S. financial markets. We are
currently evaluating the provisions of the Dodd-Frank
Act. Additionally, the Dodd-Frank Act calls for various regulatory
agencies, including the SEC and the Commodities Futures Trading Commission, to
establish regulations for implementation of many of the provisions of the
Dodd-Frank Act, which we expect will provide additional clarity regarding the
extent of the impact of this legislation on us. We expect to be able
to continue to participate in financial markets for hedging certain risks
inherent in our business, including commodity and interest rate
risks. However, the costs of doing so may be increased as a result of
the new legislation. We may also incur additional costs associated
with our compliance with the new regulations and anticipated additional
reporting and disclosure obligations.
Health Care Legislation - In
March 2010, the Patient Protection and Affordable Care Act and the Health Care
and Education Reconciliation Act of 2010 (collectively, the Health Care Acts)
were signed into law. Based on our preliminary analysis of the Health
Care Acts, we do not expect a significant impact to our benefit plans or their
related costs. We do not participate in the federal retiree
prescription drug subsidy program, for which the tax treatment was changed as a
result of the Health Care Acts, and accordingly, are not impacted by the change
in tax treatment of the subsidy. With the exception of increasing our
dependent care age requirement to age 26 from age 24, our health plans provide
coverage levels that meet the near-term minimum requirements outlined in the
Health Care Acts. We continue to evaluate the implications of the
provisions of the Health Care Acts and expect to continue to provide benefit
plan options that meet the provisions outlined by the Health Care
Acts.
Other - Several regulatory
initiatives impacted the earnings and future earnings potential for our
Distribution segment. See discussion of our Distribution segment’s
regulatory initiatives on page 45.
37
IMPACT
OF NEW ACCOUNTING STANDARDS
Information
about the impact of new accounting standards is included in Note A of the Notes to Consolidated Financial
Statements in this Quarterly Report for ASU 2010-06, “Improving Disclosures
about Fair Value Measurements,” which did not have a material impact on our
consolidated financial statements and related disclosures. See
Note B of the Notes to Consolidated
Financial Statements for discussion of our fair value measurements;
CRITICAL
ACCOUNTING POLICIES AND ESTIMATES
The
preparation of our consolidated financial statements and related disclosures in
accordance with GAAP requires us to make estimates and assumptions with respect
to values or conditions that cannot be known with certainty that affect the
reported amount of assets and liabilities, and the disclosure of contingent
assets and liabilities at the date of the consolidated financial
statements. These estimates and assumptions also affect the reported
amounts of revenues and expenses during the reporting
period. Although we believe these estimates and assumptions are
reasonable, actual results could differ from our estimates.
Information
about our critical accounting policies and estimates is included under Item 7,
Management’s Discussion and Analysis of Financial Condition and Results of
Operations, “Critical Accounting Policies and Estimates,” in our Annual
Report.
FINANCIAL
RESULTS AND OPERATING INFORMATION
Consolidated
Operations
Selected Financial Results -
The following table sets forth certain selected consolidated financial results
for the periods indicated:
Three
Months Ended
|
Six
Months Ended
|
Increase
(Decrease)
|
Increase
(Decrease)
|
||||||||||||||||||||||||
June
30,
|
June
30,
|
Three
Months
|
Six
Months
|
||||||||||||||||||||||||
Financial
Results
|
2010
|
2009
|
2010
|
2009
|
2010
vs. 2009
|
2010
vs. 2009
|
|||||||||||||||||||||
(Millions of dollars) | |||||||||||||||||||||||||||
Revenues
|
$ | 2,807.1 | $ | 2,227.6 | $ | 6,731.1 | $ | 5,017.4 | $ | 579.5 | 26 | % | $ | 1,713.7 | 34 | % | |||||||||||
Cost
of sales and fuel
|
2,349.0 | 1,795.2 | 5,653.7 | 4,033.6 | 553.8 | 31 | % | 1,620.1 | 40 | % | |||||||||||||||||
Net
margin
|
458.1 | 432.4 | 1,077.4 | 983.8 | 25.7 | 6 | % | 93.6 | 10 | % | |||||||||||||||||
Operating
costs
|
203.6 | 210.1 | 406.9 | 397.1 | (6.5 | ) | (3 | %) | 9.8 | 2 | % | ||||||||||||||||
Depreciation
and amortization
|
75.5 | 71.2 | 153.4 | 143.4 | 4.3 | 6 | % | 10.0 | 7 | % | |||||||||||||||||
Gain
(loss) on sale of assets
|
(0.3 | ) | 3.7 | (1.1 | ) | 4.5 | (4.0 | ) | * | (5.6 | ) | * | |||||||||||||||
Operating
income
|
$ | 178.7 | $ | 154.8 | $ | 516.0 | $ | 447.8 | $ | 23.9 | 15 | % | $ | 68.2 | 15 | % | |||||||||||
Equity
earnings from investments
|
$ | 20.7 | $ | 14.2 | $ | 41.8 | $ | 35.4 | $ | 6.5 | 46 | % | $ | 6.4 | 18 | % | |||||||||||
Allowance
for equity funds used
during
construction
|
$ | 0.2 | $ | 9.5 | $ | 0.5 | $ | 18.5 | $ | (9.3 | ) | (98 | %) | $ | (18.0 | ) | (97 | %) | |||||||||
Interest
expense
|
$ | (75.4 | ) | $ | (73.4 | ) | $ | (151.9 | ) | $ | (151.4 | ) | $ | 2.0 | 3 | % | $ | 0.5 | 0 | % | |||||||
Net
income attributable to
noncontrolling
interests
|
$ | (44.7 | ) | $ | (39.7 | ) | $ | (76.8 | ) | $ | (80.9 | ) | $ | 5.0 | 13 | % | $ | (4.1 | ) | (5 | %) | ||||||
Capital
expenditures
|
$ | 111.4 | $ | 164.6 | $ | 179.7 | $ | 407.6 | $ | (53.2 | ) | (32 | %) | $ | (227.9 | ) | (56 | %) | |||||||||
*
Percentage change is greater than 100 percent.
|
Energy markets were affected by
increased commodity prices during the three and six months ended June 30, 2010,
compared with the same periods last year. This increase in commodity
prices impacted our revenues and cost of sales and fuel.
Net
margin increased for the three months ended June 30, 2010, compared with the
same period last year, due primarily to the following:
·
|
increased
net margin in our ONEOK Partners segment, due primarily
to:
|
-
|
higher
NGL volumes gathered, fractionated and transported, associated with the
completion of ONEOK Partners’ capital projects, as well as new NGL supply
connections, offset partially by lower optimization margins as increasing
NGL volumes from customers under fee-based contracts limited the
fractionation and transportation capacity available for optimization
activities, offset partially by increased volumes
marketed;
|
38
-
|
increased
natural gas transportation capacity contracted and the impact of higher
natural gas prices on retained
fuel;
|
·
|
increased
net margin in our Distribution segment from new rates in Oklahoma, which
have a rate design that lowers our volumetric sensitivity; offset
partially by
|
·
|
decreased
net margin in our Energy Services segment, due primarily
to:
|
-
|
decreased
transportation margins, net of hedging, due primarily to lower realized
Mid-Continent-to-Gulf Coast location differentials;
and
|
-
|
lower
realized seasonal storage differentials and marketing margins, net of
hedging activities.
|
Net
margin increased for the six months ended June 30, 2010, compared with the same
period last year, due primarily to the following:
·
|
increased
net margin in our Energy Services segment, due primarily
to:
|
-
|
higher
realized seasonal storage differentials and marketing margins, net of
hedging activities; offset partially
by
|
-
|
decreased
premium-services margins, associated primarily with lower demand fees and
managing increased demand to meet customer-peaking requirements due to
colder weather in the first quarter of 2010, compared with the same period
last year;
|
·
|
increased
net margin in our ONEOK Partners segment, due primarily
to:
|
-
|
higher
NGL volumes gathered, fractionated and transported, associated with the
completion of ONEOK Partners’ capital projects, as well as new NGL supply
connections; and
|
-
|
higher
natural gas transportation margins from an increase in capacity contracted
on Midwestern Gas Transmission, Viking Gas Transmission’s Fargo lateral
that was completed in October 2009 and from the Guardian Pipeline
expansion and extension project that was completed in February 2009;
offset partially by
|
-
|
lower
optimization margins as increasing NGL volumes from customers under
fee-based contracts limited the fractionation and transportation capacity
available for optimization activities, offset partially by increased
volumes marketed;
|
·
|
increased
net margin in our Distribution segment from new rates in Oklahoma, which
have a rate design that lowers our volumetric
sensitivity.
|
Operating
costs decreased for the three months ended June 30, 2010, compared with the same
period last year, due primarily to the timing of certain accruals for
employee-related costs, offset partially by the recognition of previously
deferred costs in our Distribution segment.
Operating
costs increased for the six months ended June 30, 2010, compared with the same
period last year, due to the recognition of previously deferred costs in our
Distribution segment, and the operation of the capital projects completed last
year and higher employee-related costs in our ONEOK Partners
segment.
Depreciation
and amortization expense increased for the three and six months ended June 30,
2010, compared with the same periods last year, primarily as a result of ONEOK
Partners’ completed capital projects.
Equity
earnings from investments increased for the three and six months ended June 30,
2010, compared with the same periods last year, as a result of increased
throughput on Northern Border Pipeline. ONEOK Partners owns a 50
percent equity interest in Northern Border Pipeline.
Allowance
for equity funds used during construction and capital expenditures decreased for
the three and six months ended June 30, 2010, compared with the same periods
last year, primarily as a result of ONEOK Partners’ completed capital
projects.
Additional
information regarding our financial results and operating information is
provided in the following discussion for each of our segments.
ONEOK
Partners
Overview - We currently own
approximately 42.4 million common and Class B limited partner units and the
entire 2 percent general partner interest, which, together, represent a 42.8
percent ownership interest in ONEOK Partners. We receive
distributions from ONEOK Partners on our common and Class B units and our 2
percent general partner interest.
39
Our ONEOK
Partners segment is engaged in the gathering and processing of natural gas
produced from crude oil and natural gas wells, primarily in the Mid-Continent
and Rocky Mountain regions, which include the Anadarko Basin of Oklahoma that
contains the NGL-rich Woodford shale formation, Hugoton and Central Kansas
Uplift Basins of Kansas, and the Williston Basin of
Montana and North Dakota that includes the oil-producing Bakken and Three Forks
shale formations, and the Powder River Basin of Wyoming. Through
gathering systems, natural gas is aggregated and treated or processed for
removal of water vapor, solids and other contaminants, and to extract NGLs in
order to provide marketable natural gas, commonly referred to as residue
gas. When the NGLs are separated from the unprocessed natural gas at
the processing plants, the NGLs are generally in the form of a mixed,
unfractionated NGL stream. In the Powder River Basin, the natural gas
that ONEOK Partners gathers is coal-bed methane, or dry gas, that does not
require processing or NGL extraction, in order to be marketable; dry gas is
gathered, compressed and delivered into a downstream pipeline or marketed for a
fee.
ONEOK
Partners operates interstate and intrastate natural gas transmission pipelines,
natural gas storage facilities and non-processable natural gas gathering
facilities. ONEOK Partners also provides natural gas transportation
and storage services in accordance with Section 311(a) of the Natural Gas Policy
Act of 1978, as amended. ONEOK Partners’ interstate assets transport
natural gas through FERC-regulated interstate natural gas pipelines that access
supply from Canada and from the Mid-Continent, Rocky Mountain and Gulf Coast
regions. ONEOK Partners’ intrastate natural gas pipeline assets are
located in Oklahoma, Texas and Kansas, and have access to major natural gas
producing areas in those states. ONEOK Partners owns underground
natural gas storage facilities in Oklahoma, Kansas and Texas.
ONEOK
Partners also gathers, treats, fractionates, transports and stores
NGLs. ONEOK Partners’ natural gas liquids gathering pipelines deliver
unfractionated NGLs gathered from natural gas processing plants located in
Oklahoma, Kansas, Texas and the Rocky Mountain region to fractionators it owns
in Oklahoma, Kansas and Texas. The NGLs are then separated through
the fractionation process into the individual NGL products that realize the
greater economic value of the NGL components. The individual NGL
products are then stored or distributed to petrochemical manufacturers, heating
fuel users, refineries and propane distributors through ONEOK Partners’
FERC-regulated distribution pipelines that move NGL products from Oklahoma and
Kansas to the market centers in Conway, Kansas, and Mont Belvieu, Texas, as well
as the Midwest markets near Chicago, Illinois.
Selected Financial Results and
Operating Information - The following table sets forth certain selected
financial results for our ONEOK Partners segment for the periods
indicated:
Three
Months Ended
|
Six
Months Ended
|
Increase
(Decrease)
|
Increase
(Decrease)
|
||||||||||||||||||||
June
30,
|
June
30,
|
Three
Months
|
Six
Months
|
||||||||||||||||||||
Financial
Results
|
2010
|
2009
|
2010
|
2009
|
2010
vs. 2009
|
2010
vs. 2009
|
|||||||||||||||||
(Millions
of dollars)
|
|||||||||||||||||||||||
Revenues
|
$ | 2,055.1 | $ | 1,397.1 | $ | 4,259.1 | $ | 2,647.9 | $ | 658.0 | 47 | % | $ | 1,611.2 | 61 | % | |||||||
Cost
of sales and fuel
|
1,766.9 | 1,135.1 | 3,709.8 | 2,132.3 | 631.8 | 56 | % | 1,577.5 | 74 | % | |||||||||||||
Net
margin
|
288.2 | 262.0 | 549.3 | 515.6 | 26.2 | 10 | % | 33.7 | 7 | % | |||||||||||||
Operating
costs
|
97.9 | 100.5 | 194.3 | 190.0 | (2.6 | ) | (3 | %) | 4.3 | 2 | % | ||||||||||||
Depreciation
and amortization
|
44.0 | 40.0 | 87.9 | 79.9 | 4.0 | 10 | % | 8.0 | 10 | % | |||||||||||||
Gain
(loss) on sale of assets
|
(0.3 | ) | 3.3 | (1.0 | ) | 3.9 | (3.6 | ) | * | (4.9 | ) | * | |||||||||||
Operating
income
|
$ | 146.0 | $ | 124.8 | $ | 266.1 | $ | 249.6 | $ | 21.2 | 17 | % | $ | 16.5 | 7 | % | |||||||
Equity
earnings from investments
|
$ | 20.7 | $ | 14.2 | $ | 41.8 | $ | 35.4 | $ | 6.5 | 46 | % | $ | 6.4 | 18 | % | |||||||
Allowance
for equity funds used
during
construction
|
$ | 0.2 | $ | 9.5 | $ | 0.5 | $ | 18.5 | $ | (9.3 | ) | (98 | %) | $ | (18.0 | ) | (97 | %) | |||||
Interest
expense
|
$ | (53.3 | ) | $ | (50.9 | ) | $ | (107.5 | ) | $ | (101.8 | ) | $ | 2.4 | 5 | % | $ | 5.7 | 6 | % | |||
Capital
expenditures
|
$ | 62.9 | $ | 129.4 | $ | 98.7 | $ | 321.9 | $ | (66.5 | ) | (51 | %) | $ | (223.2 | ) | (69 | %) | |||||
*
Percentage change is greater than 100 percent.
|
Net
margin increased for the three months ended June 30, 2010, compared with the
same period last year, due to the following:
·
|
an
increase of $26.7 million due to higher NGL volumes gathered, fractionated
and transported, associated with the completion of ONEOK Partners’ capital
projects, as well as new NGL supply
connections;
|
·
|
an
increase of $5.2 million due to an increase in natural gas transportation
capacity contracted and the impact of higher natural gas prices on
retained fuel;
|
·
|
an
increase of $4.4 million due to the impact of NGL operational measurement
gains and losses, compared with the same period last year;
and
|
40
·
|
an
increase of $4.0 million from higher net realized commodity prices; offset
partially by
|
·
|
a
decrease of $14.2 million related to lower optimization margins as
increasing NGL volumes from customers under fee-based contracts limited
the fractionation and transportation capacity available for optimization
activities, offset partially by increased volumes
marketed.
|
Net
margin increased for the six months ended June 30, 2010, compared with the same
period last year, due to the following:
·
|
an
increase of $44.8 million due to higher NGL volumes gathered, fractionated
and transported, associated with the completion of ONEOK Partners’ capital
projects, as well as new NGL supply
connections;
|
·
|
an
increase of $11.7 million from higher natural gas transportation margins
from an increase in capacity contracted on Midwestern Gas Transmission,
Viking Gas Transmission’s Fargo lateral that was completed in October 2009
and from the Guardian Pipeline expansion and extension project that was
completed in February 2009; and
|
·
|
an
increase of $4.8 million due to higher natural gas storage margins as a
result of contract renegotiations; offset partially
by
|
·
|
a
decrease of $29.0 million related to lower optimization margins as
increasing NGL volumes from customers under fee-based contracts limited
the fractionation and transportation capacity available for optimization
activities, offset partially by increased volumes
marketed.
|
Operating
costs decreased for the three months ended June 30, 2010, compared with the same
period last year, due primarily to the timing of certain accruals for
employee-related costs, offset partially by the operations of ONEOK Partners’
capital projects completed last year. Operating costs increased for
the six months ended June 30, 2010, compared with the same period last year, due
to the operation of ONEOK Partners’ completed capital projects and higher
employee-related costs.
Depreciation
and amortization expense increased for the three and six months ended June 30,
2010, compared with the same periods last year, as a result of ONEOK Partners’
capital projects completed last year.
Equity
earnings from investments increased for the three and six months ended June 30,
2010, compared with the same periods last year, as a result of increased
throughput on Northern Border Pipeline.
Allowance
for equity funds used during construction and capital expenditures decreased for
the three and six months ended June 30, 2010, compared with the same periods
last year, as a result of ONEOK Partners’ completed capital
projects.
Selected Operating Information
- The following table sets forth selected operating information for our ONEOK
Partners segment for the periods indicated:
Three
Months Ended
|
Six
Months Ended
|
|||||||||||||||
June
30,
|
June
30,
|
|||||||||||||||
Operating
Information
|
2010
|
2009
|
2010
|
2009
|
||||||||||||
Natural
gas gathered (BBtu/d)
(a)
|
1,088 | 1,130 | 1,090 | 1,147 | ||||||||||||
Natural
gas processed (BBtu/d)
(a)
|
690 | 658 | 677 | 655 | ||||||||||||
Natural
gas transportation capacity contracted (MMcf/d)
|
5,454 | 5,192 | 5,656 | 5,220 | ||||||||||||
Transportation
capacity subscribed
|
84 | % | 79 | % | 87 | % | 79 | % | ||||||||
Residue
gas sales (BBtu/d)
(a)
|
290 | 291 | 283 | 288 | ||||||||||||
NGL
sales (MBbl/d)
|
449 | 401 | 438 | 391 | ||||||||||||
NGLs
fractionated (MBbl/d)
|
524 | 479 | 508 | 472 | ||||||||||||
NGLs
transported-gathering lines (MBbl/d)
|
480 | 364 | 460 | 344 | ||||||||||||
NGLs
transported-distribution lines (MBbl/d)
|
482 | 461 | 475 | 453 | ||||||||||||
Conway-to-Mont
Belvieu OPIS average price differential
|
||||||||||||||||
Ethane
($/gallon)
|
$ | 0.16 | $ | 0.12 | $ | 0.12 | $ | 0.10 | ||||||||
Realized
composite NGL net sales price ($/gallon) (a)
(b)
|
$ | 0.90 | $ | 0.84 | $ | 0.94 | $ | 0.85 | ||||||||
Realized
condensate net sales price ($/Bbl) (a)
(b)
|
$ | 63.45 | $ | 77.03 | $ | 62.92 | $ | 72.51 | ||||||||
Realized
residue gas net sales price ($/MMBtu) (a)
(b)
|
$ | 5.37 | $ | 3.21 | $ | 5.33 | $ | 3.42 | ||||||||
Realized
gross processing spread
($/MMBtu) (a)
|
$ | 3.48 | $ | 6.34 | $ | 3.70 | $ | 6.34 | ||||||||
(a)
- Statistics relate to ONEOK Partners’ natural gas gathering and
processing business.
|
||||||||||||||||
(b)
- Includes equity volumes only.
|
41
Commodity Price Risk - The
following tables set forth hedging information for ONEOK Partners’ natural gas
gathering and processing business for the periods indicated:
Six Months Ended | ||||||||||
December 31, 2010 | ||||||||||
Volumes
Hedged
|
Average
Price
|
Percentage
Hedged
|
||||||||
NGLs
(Bbl/d)
(a)
|
5,166 | $ | 1.05 |
/
gallon
|
60 | % | ||||
Condensate
(Bbl/d)
(a)
|
1,611 | $ | 1.83 |
/
gallon
|
76 | % | ||||
Total
(Bbl/d)
|
6,777 | $ | 1.24 |
/
gallon
|
63 | % | ||||
Natural
gas
(MMBtu/d)
|
23,345 | $ | 5.55 |
/
MMBtu
|
95 | % | ||||
(a)
- Hedged with fixed-price swaps.
|
Year
Ending
|
|||||||||||||
December
31, 2011
|
|||||||||||||
Volumes
Hedged
|
Average
Price
|
Percentage
Hedged
|
|||||||||||
NGLs
(Bbl/d)
(a)
|
902 | $ | 1.34 |
/
gallon
|
10 | % | |||||||
Condensate
(Bbl/d)
(a)
|
596 | $ | 2.12 |
/
gallon
|
26 | % | |||||||
Total
(Bbl/d)
|
1,498 | $ | 1.65 |
/
gallon
|
13 | % | |||||||
Natural
gas
(MMBtu/d)
|
22,541 | $ | 5.72 |
/
MMBtu
|
75 | % | |||||||
(a)
- Hedged with fixed-price swaps.
|
Commodity
price risk related to physical sales of commodities for ONEOK Partners’ natural
gas gathering and processing business is estimated as a hypothetical change in
the price of NGLs, crude oil and natural gas. ONEOK Partners’
condensate sales are based on the price of crude oil. ONEOK Partners
estimates the following for its natural gas gathering and processing
business:
·
|
a
$0.01 per gallon decrease in the composite price of NGLs would decrease
annual net margin by approximately $1.3
million;
|
·
|
a
$1.00 per barrel decrease in the price of crude oil would decrease annual
net margin by approximately $1.1 million;
and
|
·
|
a
$0.10 per MMBtu decrease in the price of natural gas would decrease annual
net margin by approximately $1.0
million.
|
The above
estimates of commodity price risk exclude the effects of hedging and assume
normal operating conditions. Further, these estimates do not include
any effects on demand for ONEOK Partners’ services or processing plant
operations that might be caused by, or arise in conjunction with, price
changes. For example, a change in the gross processing spread may
cause a change in the amount of ethane extracted from the natural gas stream,
affecting gathering and processing margins.
See
Note C of the Notes to Consolidated Financial Statements in this Quarterly
Report for more information on our hedging activities.
Distribution
Overview - Our Distribution
segment provides natural gas distribution services to more than two million
customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas
Service and Texas Gas Service, respectively, each a division of
ONEOK. We serve residential, commercial, industrial and
transportation customers in all three states. Our distribution
companies in Oklahoma and Kansas serve wholesale customers, and in Texas we
serve public authority customers, such as cities, governmental agencies and
schools. In addition, our retail marketing business serves customers
primarily in the Mid-Continent region.
42
Selected Financial Results -
The following table sets forth certain selected financial results for our
Distribution segment for the periods indicated:
Three
Months Ended
|
Six
Months Ended
|
Increase
(Decrease)
|
Increase
(Decrease)
|
||||||||||||||||||||
June
30,
|
June
30,
|
Three
Months
|
Six
Months
|
||||||||||||||||||||
Financial
Results
|
2010
|
2009
|
2010
|
2009
|
2010
vs. 2009
|
2010
vs. 2009
|
|||||||||||||||||
(Millions
of dollars)
|
|||||||||||||||||||||||
Gas
sales
|
$ | 313.3 | $ | 300.2 | $ | 1,275.8 | $ | 1,113.4 | $ | 13.1 | 4 | % | $ | 162.4 | 15 | % | |||||||
Transportation
revenues
|
18.5 | 19.2 | 48.1 | 45.8 | (0.7 | ) | (4 | %) | 2.3 | 5 | % | ||||||||||||
Cost
of gas
|
180.8 | 184.4 | 935.3 | 797.1 | (3.6 | ) | (2 | %) | 138.2 | 17 | % | ||||||||||||
Net
margin, excluding other revenues
|
151.0 | 135.0 | 388.6 | 362.1 | 16.0 | 12 | % | 26.5 | 7 | % | |||||||||||||
Other
revenues
|
10.5 | 11.4 | 19.7 | 23.3 | (0.9 | ) | (8 | %) | (3.6 | ) | (15 | %) | |||||||||||
Net
margin
|
161.5 | 146.4 | 408.3 | 385.4 | 15.1 | 10 | % | 22.9 | 6 | % | |||||||||||||
Operating
costs
|
98.3 | 101.1 | 198.0 | 192.6 | (2.8 | ) | (3 | %) | 5.4 | 3 | % | ||||||||||||
Depreciation
and amortization
|
30.9 | 30.7 | 64.2 | 62.3 | 0.2 | 1 | % | 1.9 | 3 | % | |||||||||||||
Gain
(loss) on sale of assets
|
- | 0.4 | - | 0.4 | (0.4 | ) | (100 | %) | (0.4 | ) | (100 | %) | |||||||||||
Operating
income
|
$ | 32.3 | $ | 15.0 | $ | 146.1 | $ | 130.9 | $ | 17.3 | * | $ | 15.2 | 12 | % | ||||||||
Capital
expenditures
|
$ | 46.9 | $ | 32.6 | $ | 78.3 | $ | 77.3 | $ | 14.3 | 44 | % | $ | 1.0 | 1 | % | |||||||
*
Percentage change is greater than 100 percent.
|
The
following table sets forth our net margin, excluding other revenues, by type of
customer, for the periods indicated:
Three
Months Ended
|
Six
Months Ended
|
Increase
(Decrease)
|
Increase
(Decrease)
|
||||||||||||||||||||
June
30,
|
June
30,
|
Three
Months
|
Six
Months
|
||||||||||||||||||||
Net
margin, excluding other revenues
|
2010
|
2009
|
2010
|
2009
|
2010
vs. 2009
|
2010
vs. 2009
|
|||||||||||||||||
Gas
sales
|
(Millions
of dollars)
|
||||||||||||||||||||||
Regulated
|
|||||||||||||||||||||||
Residential
|
$ | 106.0 | $ | 88.4 | $ | 271.1 | $ | 244.9 | $ | 17.6 | 20 | % | $ | 26.2 | 11 | % | |||||||
Commercial
|
22.5 | 19.1 | 58.9 | 56.5 | 3.4 | 18 | % | 2.4 | 4 | % | |||||||||||||
Industrial
|
0.6 | 0.6 | 1.3 | 1.4 | - | 0 | % | (0.1 | ) | (7 | %) | ||||||||||||
Wholesale
|
0.1 | 0.1 | 0.2 | 0.2 | - | 0 | % | - | 0 | % | |||||||||||||
Public
Authority
|
0.8 | 0.7 | 2.3 | 2.0 | 0.1 | 14 | % | 0.3 | 15 | % | |||||||||||||
Retail
marketing
|
2.5 | 6.9 | 6.7 | 11.3 | (4.4 | ) | (64 | %) | (4.6 | ) | (41 | %) | |||||||||||
Net
margin on gas sales
|
132.5 | 115.8 | 340.5 | 316.3 | 16.7 | 14 | % | 24.2 | 8 | % | |||||||||||||
Transportation
margin
|
18.5 | 19.2 | 48.1 | 45.8 | (0.7 | ) | (4 | %) | 2.3 | 5 | % | ||||||||||||
Net
margin, excluding other revenues
|
$ | 151.0 | $ | 135.0 | $ | 388.6 | $ | 362.1 | $ | 16.0 | 12 | % | $ | 26.5 | 7 | % |
Net
margin increased for the three months ended June 30, 2010, compared with the
same period last year, due to the following:
·
|
an
increase of $17.2 million from new rates in Oklahoma, which have a rate
design that lowers our volumetric sensitivity and provides more consistent
revenues each month; and
|
·
|
an
increase of $1.4 million from increased rider and surcharge recoveries;
offset partially by
|
·
|
a
decrease of $4.3 million in retail marketing margins associated primarily
with reduced customer risk-management
services.
|
Net
margin increased for the six months ended June 30, 2010, compared with the same
period last year, due to the following:
·
|
an
increase of $17.1 million from new rates in Oklahoma, which have a rate
design that lowers our volumetric sensitivity and provides more consistent
revenues each month;
|
·
|
an
increase of $4.2 million from increased rider and surcharge
recoveries;
|
·
|
an
increase of $2.9 million from higher gas sales volumes, primarily in the
first quarter;
|
·
|
an
increase of $1.8 million from capital-recovery mechanisms;
and
|
·
|
an
increase of $1.7 million from higher transportation volumes; offset
partially by
|
·
|
a
decrease of $4.5 million in retail marketing margins associated primarily
with reduced customer risk-management
services.
|
43
Operating
costs decreased for the three months ended June 30, 2010, compared with the same
period last year, due to the following:
·
|
a
decrease of $8.1 million in employee-related costs; offset partially
by
|
·
|
an
increase of $3.8 million related to the recognition of previously deferred
Integrity Management Program costs in Oklahoma that have been approved for
recovery in our revenues.
|
Operating
costs increased for the six months ended June 30, 2010, compared with the same
period last year, due to the following:
·
|
an
increase of $6.9 million related to the recognition of previously deferred
Integrity Management Program costs in Oklahoma that have been approved for
recovery in our revenues; and
|
·
|
an
increase of $1.4 million related to contract and outside services costs;
offset partially by
|
·
|
a
decrease of $4.8 million in employee-related
costs.
|
Capital Expenditures - Our
capital expenditure program includes expenditures for extending service to new
areas, modifications to customer service lines, increasing system capabilities,
general replacements and improvements, including an automated meter reading
investment in Oklahoma. It is our practice to maintain and upgrade
facilities to ensure safe, reliable and efficient operations. Our
capital expenditure program included $7.3 million and $9.5 million for new
business development for the three months ended June 30, 2010 and 2009,
respectively, and $12.5 million and $20.5 million for the six months ended June
30, 2010 and 2009, respectively. Capital expenditures increased for
the three months ended June 30, 2010, compared with the same period last year,
primarily as a result of expenditures related to the automated meter reading
investment in Oklahoma.
Selected Operating Information
- The following tables set forth selected information for the regulated
operations of our Distribution segment for the periods indicated:
Three
Months Ended
|
Six
Months Ended
|
|||||||||||
June
30,
|
June
30,
|
|||||||||||
Volumes
(MMcf)
|
2010
|
2009
|
2010
|
2009
|
||||||||
Gas
sales
|
||||||||||||
Residential
|
12,246 | 13,388 | 74,702 | 68,745 | ||||||||
Commercial
|
4,245 | 4,459 | 21,423 | 20,211 | ||||||||
Industrial
|
232 | 156 | 625 | 668 | ||||||||
Wholesale
|
3,234 | 3,578 | 3,475 | 4,712 | ||||||||
Public
Authority
|
387 | 371 | 1,630 | 1,218 | ||||||||
Total
volumes sold
|
20,344 | 21,952 | 101,855 | 95,554 | ||||||||
Transportation
|
48,154 | 47,432 | 110,308 | 103,396 | ||||||||
Total
volumes delivered
|
68,498 | 69,384 | 212,163 | 198,950 |
Three
Months Ended
|
Six
Months Ended
|
|||||||||||
June
30,
|
June
30,
|
|||||||||||
Number
of Customers
|
2010
|
2009
|
2010
|
2009
|
||||||||
Residential
|
1,917,053 | 1,904,675 | 1,923,865 | 1,909,012 | ||||||||
Commercial
|
154,231 | 157,463 | 155,859 | 158,957 | ||||||||
Industrial
|
1,282 | 1,364 | 1,289 | 1,368 | ||||||||
Wholesale
|
35 | 27 | 35 | 27 | ||||||||
Public
Authority
|
2,680 | 2,858 | 2,651 | 2,903 | ||||||||
Transportation
|
7,757 | 9,075 | 9,447 | 9,911 | ||||||||
Total
customers
|
2,083,038 | 2,075,462 | 2,093,146 | 2,082,178 |
Residential
volumes decreased for the three months ended June 30, 2010, compared with the
same period last year, due to warmer temperatures across our entire service
territory. Residential volumes increased for the six months ended
June 30, 2010, compared with the same period last year, due to colder
temperatures across our entire service territory in the first quarter of
2010.
44
Regulatory
Initiatives
Oklahoma - In
December 2009, the OCC approved a rate increase of $54.5 million, which includes
moving existing riders into base rates that effectively reduces the rate
increase to a net amount of $25.7 million. The new rates went into
effect on December 18, 2009, and reduce our volumetric
exposure. Under a previous order, Oklahoma Natural Gas has migrated
from traditional rates to performance-based rates that will provide for a
streamlined annual review of the company’s performance, resulting in smaller,
potentially more frequent rate adjustments.
On
January 27, 2010, Oklahoma Natural Gas filed an application and supporting
testimony requesting recovery of the Integrity Management Program deferral for
2009 and annual adjustments associated with the prior recovery period in the
amount of $15.7 million. In May 2010, Oklahoma Natural Gas filed
supplemental testimony to increase the total amount of the request to $16.7
million. The OCC approved the recovery of $16.7 million on June 30,
2010, and billing of the new rates began July 1, 2010.
Kansas - In December
2009, the KCC approved Kansas Gas Service’s application to increase the Gas
System Reliability Surcharge. In April 2010, the surcharge recovery
was slightly reduced as a result of a revised application. The
anticipated impact of the Gas System Reliability Surcharge on 2010 operating
income is an increase of $3.4 million.
In May
2010, Kansas Gas Service was granted a motion to withdraw its application with
the KCC to become an Efficiency Kansas Loan Program utility partner and provide
a portfolio of energy-efficiency programs designed to encourage the purchase of
energy-efficient natural gas appliances. The application was
withdrawn as a result of the wide discrepancy between the positions of the
parties involved in the case. Kansas Gas Service will continue to
explore opportunities to promote energy-efficiency initiatives in a manner that
does not penalize Kansas Gas Service and meets regulators’
requirements.
Texas - In December
2009, Texas Gas Service filed a statement of intent to increase rates in its El
Paso service area by $7.3 million. On April 13, 2010, the City of El Paso
rejected the proposed increase. Texas Gas Service filed an appeal on
May 12, 2010, with the Railroad Commission of Texas, which includes a statement
of intent to increase rates by $5.3 million. The Railroad Commission
will have approximately six months to make a decision on our
appeal. Any new rates determined by the Railroad Commission would
likely go into effect late in the fourth quarter of this year.
General - Certain costs to be
recovered through the ratemaking process have been capitalized as regulatory
assets. Should recovery cease due to regulatory actions, certain of
these assets may no longer meet the criteria for capitalization, and,
accordingly, a write-off of regulatory assets and stranded costs may be
required. There were no write-offs of regulatory assets resulting
from the failure to meet the criteria for capitalization during the three and
six months ended June 30, 2010 and 2009, respectively.
Energy
Services
Overview - Our Energy Services
segment’s primary focus is to create value for our customers by delivering
physical natural gas products and risk-management services through our network
of contracted transportation and storage capacity and natural gas
supply. This contracted storage and transportation capacity connects
the major supply and demand centers throughout the United States and into
Canada. Our customers are primarily LDCs, electric utilities, and
commercial and industrial end- users. Our customers’ natural gas
needs vary with seasonal changes in weather and are therefore somewhat
unpredictable.
To ensure
natural gas is available when our customers need it, we provide premium services
and products that satisfy our customers’ swing and peaking natural gas commodity
requirements on a year-round basis. We also provide no-notice
service,
weather-related protection and other custom solutions based on our customers’
specific needs. Our storage and transportation assets enable us to
provide these services and provide us with opportunities to optimize these
contracted assets through our application of market knowledge and
risk-management skills.
Our
Energy Services segment conducts business with our ONEOK Partners and our
Distribution segments. These services are provided under agreements
with market-based terms through a competitive bidding process.
Due to
the seasonality of natural gas consumption, storage withdrawals and demand for
our products and services, earnings are normally higher during the winter months
than the summer months. Natural gas sales volumes are typically
higher in the winter heating months than in the summer months, reflecting
increased demand due to greater heating requirements and, typically, higher
natural gas prices. During periods of high natural gas demand, we
utilize storage capacity to supplement natural gas supply volumes to meet our
premium-services obligations or market needs.
45
We
utilize our experience to optimize the value of our contracted assets, and we
use our risk-management and marketing capabilities to both manage risk and
generate additional margins. We apply a combination of cash flow and
fair value hedge accounting when implementing hedging strategies that take
advantage of favorable market conditions. See Note C of the
Notes to Consolidated Financial Statements in this Quarterly Report for
additional information. Additionally, certain non-trading
transactions, which are economic hedges of our accrual transactions such as our
storage and transportation contracts, will not qualify for hedge accounting
treatment. These economic hedges receive mark-to-market accounting
treatment, as they are derivative contracts and are not designated as part of a
hedge relationship. As a result, the underlying risk being hedged
receives accrual accounting treatment, while we use mark-to-market accounting
treatment for the economic hedges. We cannot predict the earnings
fluctuations from mark-to-market accounting, and the impact on earnings could be
material.
Selected Financial Results -
The following table sets forth selected financial results for our Energy
Services segment for the periods indicated:
Three
Months Ended
|
Six
Months Ended
|
Increase
(Decrease)
|
Increase
(Decrease)
|
||||||||||||||||||||||
June
30,
|
June
30,
|
Three
Months
|
Six
Months
|
||||||||||||||||||||||
Financial
Results
|
2010
|
2009
|
2010
|
2009
|
2010
vs. 2009
|
2010
vs. 2009
|
|||||||||||||||||||
(Millions
of dollars)
|
|||||||||||||||||||||||||
Revenues
|
$ | 655.7 | $ | 722.2 | $ | 1,849.6 | $ | 1,844.2 | $ | (66.5 | ) | (9 | %) | $ | 5.4 | 0 | % | ||||||||
Cost
of sales and fuel
|
648.1 | 698.9 | 1,731.3 | 1,762.8 | (50.8 | ) | (7 | %) | (31.5 | ) | (2 | %) | |||||||||||||
Net
margin
|
7.6 | 23.3 | 118.3 | 81.4 | (15.7 | ) | (67 | %) | 36.9 | 45 | % | ||||||||||||||
Operating
costs
|
6.5 | 8.9 | 14.0 | 15.0 | (2.4 | ) | (27 | %) | (1.0 | ) | (7 | %) | |||||||||||||
Depreciation
and amortization
|
0.2 | 0.1 | 0.3 | 0.2 | 0.1 | 100 | % | 0.1 | 50 | % | |||||||||||||||
Operating
income
|
$ | 0.9 | $ | 14.3 | $ | 104.0 | $ | 66.2 | $ | (13.4 | ) | (94 | %) | $ | 37.8 | 57 | % |
The
following table sets forth our net margin by activity for the periods
indicated:
Three
Months Ended
|
Six
Months Ended
|
Increase
(Decrease)
|
Increase
(Decrease)
|
||||||||||||||||||||||
June
30,
|
June
30,
|
Three
Months
|
Six
Months
|
||||||||||||||||||||||
2010
|
2009
|
2010
|
2009
|
2010
vs. 2009
|
2010
vs. 2009
|
||||||||||||||||||||
(Millions
of dollars)
|
|||||||||||||||||||||||||
Marketing,
storage and transportation, gross
|
$ | 51.6 | $ | 74.7 | $ | 215.0 | $ | 186.6 | $ | (23.1 | ) | (31 | %) | $ | 28.4 | 15 | % | ||||||||
Storage
and transportation costs
|
45.3 | 51.6 | 100.0 | 108.6 | (6.3 | ) | (12 | %) | (8.6 | ) | (8 | %) | |||||||||||||
Marketing, storage
and transportation, net
|
6.3 | 23.1 | 115.0 | 78.0 | (16.8 | ) | (73 | %) | 37.0 | 47 | % | ||||||||||||||
Financial
trading, net
|
1.3 | 0.2 | 3.3 | 3.4 | 1.1 | * | (0.1 | ) | (3 | %) | |||||||||||||||
Net
margin
|
$ | 7.6 | $ | 23.3 | $ | 118.3 | $ | 81.4 | $ | (15.7 | ) | (67 | %) | $ | 36.9 | 45 | % | ||||||||
*
Percentage change is greater than 100 percent.
|
Marketing,
storage and transportation, gross, includes primarily marketing, purchases and
sales, premium services and the impact of cash flow and fair value hedges and
other derivative instruments used to manage our risk associated with these
activities. Storage and transportation costs include primarily the
cost of leasing capacity, storage injection and withdrawal fees, fuel charges
and gathering fees. Risk-management and operational decisions have an
impact on the net result of our marketing, premium services and storage
activities. We evaluate our strategies on an ongoing basis to
optimize the value of our contracted assets and to minimize the financial impact
of market conditions on the services we provide.
Financial
trading includes activities that are generally executed using financially
settled derivatives. These activities are normally short term in
nature, with a focus on capturing short-term price
volatility. Revenues in our Consolidated Statements of Income include
financial trading margins, as well as certain physical natural gas transactions
with our trading counterparties. Revenues and cost of sales and fuel
from such physical transactions are reported on a net basis.
Net
margin decreased for the three months ended June 30, 2010, compared with the
same period last year, due to the following:
·
|
a
decrease of $8.1 million in transportation margins, net of hedging, due
primarily to lower realized Mid-Continent-to-Gulf Coast location
differentials;
|
·
|
a
decrease of $5.9 million from lower realized seasonal storage
differentials and marketing margins, net of hedging activities;
and
|
·
|
a
decrease of $2.7 million in premium-services margins, associated primarily
with lower demand fees; offset partially
by
|
·
|
an
increase of $1.1 million in financial trading
margins.
|
46
Net
margin increased for the six months ended June 30, 2010, compared with the same
period last year, due to the following:
·
|
an
increase of $65.7 million from higher realized seasonal storage
differentials and marketing margins, net of hedging activities; offset
partially by
|
·
|
a
decrease of $25.3 million in premium-services margins, associated
primarily with lower demand fees and managing increased demand to meet
customer-peaking requirements due to colder weather in the first quarter
of 2010, compared with the same period last year;
and
|
·
|
a
decrease of $3.3 million in transportation margins, net of hedging, due
primarily to lower realized Mid-Continent-to-Gulf Coast transportation
margins; partially offset by the
following:
|
-
|
favorable
fair-value changes on non-qualifying economic hedge activity and
ineffectiveness on qualified hedges;
and
|
-
|
higher
realized Rocky Mountain-to-Mid-Continent transportation
margins.
|
Operating
costs decreased for the three months ended June 30, 2010, compared with the same
period last year, due to lower employee-related costs.
Selected Operating Information
- The following table sets forth selected operating information for our Energy
Services segment for the periods indicated:
Three
Months Ended
|
Six
Months Ended
|
|||||||||||
June
30,
|
June
30,
|
|||||||||||
Operating
Information
|
2010
|
2009
|
2010
|
2009
|
||||||||
Natural
gas marketed (Bcf)
|
201 | 257 | 468 | 585 | ||||||||
Natural
gas gross margin ($/Mcf)
|
$ | 0.04 | $ | 0.09 | $ | 0.26 | $ | 0.14 | ||||
Physically
settled volumes (Bcf)
|
435 | 542 | 944 | 1,176 |
Our
natural gas in storage at June 30, 2010, was 50.4 Bcf, compared with 68.6 Bcf at
June 30, 2009. At June 30, 2010, our total natural gas storage
capacity under lease was 74.6 Bcf, compared with 82.5 Bcf at June 30,
2009. Our natural gas storage capacity under lease had maximum
withdrawal capability of 2.0 Bcf/d and maximum injection capability of 1.2
Bcf/d. Our current natural gas transportation capacity is 1.4
Bcf/d.
Natural
gas volumes marketed and physically settled volumes decreased for the three and
six months ended June 30, 2010, compared with the same periods last year, due
primarily to reduced transportation capacity and lower transported
volumes. Transportation capacity in certain markets was not utilized
due to the economics of the location differentials.
Contingencies
Legal Proceedings - We are a
party to various litigation matters and claims that have arisen in the normal
course of our operations. While the results of litigation and claims
cannot be predicted with certainty, we believe the final outcome of such matters
will not have a material adverse effect on our consolidated results of
operations, financial position or cash flows. Additional information
about our legal proceedings is included under Part II, Item 1, Legal Proceedings
of this Quarterly Report and under Part I, Item 3, Legal Proceedings, in our
Annual Report.
LIQUIDITY
AND CAPITAL RESOURCES
General - Part of our strategy
is to grow through internally generated growth projects and acquisitions that
strengthen and complement our existing assets. ONEOK and ONEOK
Partners have relied primarily on operating cash flow, commercial paper, bank
credit facilities, debt issuances and the sale of equity for their liquidity and
capital resource requirements. ONEOK and ONEOK Partners fund their
operating expenses, debt service, dividends to shareholders and distributions to
unitholders primarily with operating cash flow. We expect to continue
to use these sources and ONEOK Partners’ recently established commercial paper
program, discussed below, for liquidity and capital resource needs on both a
short- and long-term basis. Neither ONEOK nor ONEOK Partners
guarantees the debt or other similar commitments to unaffiliated parties, and
ONEOK does not guarantee the debt or other similar commitments of ONEOK
Partners.
In the
first six months of 2010, ONEOK accessed the commercial paper markets to meet
its short-term liquidity needs. ONEOK Partners utilized the ONEOK
Partners Credit Agreement to fund its short-term liquidity needs during the
first six months of 2010. In February 2010, ONEOK Partners accessed
the public equity markets for its long-term financing needs. See
discussion below under “ONEOK Partners’ Equity Issuance” for more
information.
47
In June
2010, ONEOK Partners established a commercial paper program providing for the
issuance of up to $1.0 billion of unsecured commercial paper
notes. Amounts outstanding under the commercial paper program reduce
the borrowing capacity under the ONEOK Partners Credit Agreement. See
discussion below under “Short-term Liquidity” for more information.
We expect
a slow economic recovery to continue for the remainder of
2010. Although volatility in the financial markets could limit our
access to financial markets or increase our cost of capital in the future, we
anticipate improved credit markets for the remainder of 2010, compared with
2009. ONEOK’s and ONEOK Partners’ ability to continue to access
capital markets for debt and equity financing under reasonable terms depends on
ONEOK’s and ONEOK Partners’ respective financial condition and credit ratings,
and market conditions. ONEOK and ONEOK Partners anticipate that cash
flow generated from operations, existing capital resources and ability to obtain
financing will enable both to maintain current levels of operations and planned
operations, collateral requirements and capital expenditures.
Capital
Structure - The following table sets forth our consolidated capital
structure for the periods indicated:
June
30,
|
December
31,
|
|||||||
2010
|
2009
|
|||||||
Long-term
debt
|
53% | 57% | ||||||
Total
equity
|
47% | 43% | ||||||
Debt
(including notes payable)
|
56% | 61% | ||||||
Total
equity
|
44% | 39% |
For
purposes of determining compliance with financial covenants in the ONEOK Credit
Agreement, which are described below, the debt of ONEOK Partners is
excluded. The following table sets forth ONEOK’s capitalization
structure, excluding the debt of ONEOK Partners, for the periods
indicated:
June
30,
|
December
31,
|
|||||||
2010
|
2009
|
|||||||
Long-term
debt
|
39% | 41% | ||||||
ONEOK
shareholders' equity
|
61% | 59% | ||||||
Debt
(including notes payable)
|
39% | 46% | ||||||
ONEOK
shareholders' equity
|
61% | 54% |
Cash Management - ONEOK and
ONEOK Partners each use similar centralized cash management programs that
concentrate the cash assets of their operating subsidiaries in joint accounts
for the purpose of providing financial flexibility and lowering the cost of
borrowing, transaction costs and bank fees. Both centralized cash
management programs provide that funds in excess of the daily needs of the
operating subsidiaries are concentrated, consolidated or otherwise made
available for use by other entities within the respective consolidated
groups. ONEOK Partners’ operating subsidiaries participate in these
programs to the extent they are permitted pursuant to FERC regulations or their
operating agreements. Under these cash management programs, depending
on whether a participating subsidiary has short-term cash surpluses or cash
requirements, ONEOK and ONEOK Partners provide cash to their respective
subsidiaries or the subsidiaries provide cash to them.
Short-term Liquidity - ONEOK’s
principal sources of short-term liquidity consist of cash generated from
operating activities, quarterly distributions from ONEOK Partners and the
issuance of commercial paper. To the extent commercial paper is
unavailable the ONEOK Credit Agreement may be utilized. ONEOK
Partners’ principal sources of short-term liquidity consist of cash generated
from operating activities, the ONEOK Partners Credit Agreement and ONEOK
Partners’ recently established commercial paper program.
The total
amount of short-term borrowings authorized by ONEOK’s Board of Directors is $2.5
billion. At June 30, 2010, ONEOK had no commercial paper outstanding,
$32.0 million in letters of credit issued under the ONEOK Credit Agreement and
approximately $100.2 million of available cash and cash
equivalents. ONEOK had approximately $1.2 billion of credit available
at June 30, 2010, under the ONEOK Credit Agreement. As of June 30,
2010, ONEOK could have issued $3.7 billion of additional short- and long-term
debt under the most restrictive provisions contained in its various borrowing
agreements.
48
The total
amount of short-term borrowings authorized by the Board of Directors of ONEOK
Partners GP, the general partner of ONEOK Partners, is $1.5
billion. At June 30, 2010, ONEOK Partners had $680 million in
borrowings outstanding under the ONEOK Partners Credit Agreement and
approximately $3.1 million of available cash and cash equivalents. As
of June 30, 2010, ONEOK Partners could have issued $592.6 million of additional
short- and long-term debt under the most restrictive provisions contained in its
various borrowing agreements. At June 30, 2010, ONEOK Partners had
$24.2 million in letters of credit issued outside the ONEOK Partners Credit
Agreement.
In June
2010, ONEOK Partners initiated a commercial paper program under which ONEOK
Partners may issue unsecured commercial paper notes up to a maximum amount
outstanding of $1.0 billion to fund its short-term borrowing
needs. The maturities of the commercial paper notes will vary but may
not exceed 270 days from the date of issue. The commercial paper
notes may be sold at a negotiated discount from par or will bear interest
at a negotiated rate.
The ONEOK
Partners Credit Agreement, which expires in March 2012, is available to repay
the commercial paper notes, if necessary. Amounts outstanding under
the commercial paper program reduce the borrowing capacity under the ONEOK
Partners Credit Agreement. At June 30, 2010, ONEOK Partners had not
issued any commercial paper. In July 2010, ONEOK Partners repaid all
borrowings outstanding under the ONEOK Partners Credit Agreement with proceeds
from the issuance of commercial paper.
The ONEOK
Credit Agreement and the ONEOK Partners Credit Agreement contain certain
financial, operational and legal covenants as discussed in Note H of the Notes
to Consolidated Financial Statements in our Annual Report. Among
other things, the ONEOK Credit Agreement’s covenants include a limitation on
ONEOK’s stand-alone debt-to-capital ratio, which may not exceed 67.5 percent at
the end of any calendar quarter. At June 30, 2010, ONEOK’s
stand-alone debt-to-capital ratio, as calculated under the terms of the ONEOK
Credit Agreement, was 38.2 percent, and ONEOK was in compliance with all
covenants under the ONEOK Credit Agreement.
The ONEOK
Partners Credit Agreement’s covenants include, among other things, maintaining a
ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in the ONEOK
Partners Credit Agreement, adjusted for all non-cash charges and increased for
projected EBITDA from certain lender-approved capital expansion projects) of no
more than 5 to 1. At June 30, 2010, ONEOK Partners’ ratio of
indebtedness to adjusted EBITDA was 4.3 to 1, and ONEOK Partners was in
compliance with all covenants under the ONEOK Partners Credit
Agreement.
Long-term Financing - In
addition to the principal sources of short-term liquidity discussed above,
options available to ONEOK to meet its longer-term cash requirements include the
issuance of equity, issuance of long-term notes, issuance of convertible debt
securities, asset securitization and the sale and leaseback of
facilities. Options available to ONEOK Partners to meet its
longer-term cash requirements include the issuance of common units, issuance of
long-term notes, issuance of convertible debt securities, asset securitization
and the sale and leaseback of facilities.
ONEOK and
ONEOK Partners are subject to changes in the debt and equity markets, and there
is no assurance they will be able or willing to access the public or private
markets in the future. ONEOK and ONEOK Partners may choose to meet
their cash requirements by utilizing some combination of cash flows from
operations, commercial paper borrowings or existing credit facilities, altering
the timing of controllable expenditures, restricting future acquisitions and
capital projects, or pursuing other debt or equity financing
alternatives. Some of these alternatives could involve higher costs
or negatively affect their respective credit ratings, among other
factors. Based on ONEOK’s and ONEOK Partners’ investment-grade credit
ratings, general financial condition and market expectations regarding their
future earnings and projected cash flows, ONEOK and ONEOK Partners believe that
they will be able to meet their respective cash requirements and maintain their
investment-grade credit ratings.
In June
2010, ONEOK Partners repaid $250.0 million of maturing senior notes with
available cash and short-term borrowings. With the repayment of these
notes, ONEOK Partners no longer has any obligation to offer to repurchase the
$225 million senior notes due 2011 in the event that ONEOK Partners’ long-term
debt credit ratings fall below investment grade.
The
indentures governing ONEOK’s senior notes due 2011, 2019 and 2028 include an
event of default upon acceleration of other indebtedness of $15 million or more,
and the indentures governing the senior notes due 2015 and 2035 include an event
of default upon the acceleration of other indebtedness of $100 million or
more. Such events of default would entitle the trustee or the holders
of 25 percent in aggregate principal amount of the outstanding senior notes due
2011, 2015, 2019, 2028 and 2035 to declare those notes immediately due and
payable in full.
49
ONEOK may
redeem the notes due 2011, 2015, 2028 (6.875 percent) and 2035, in whole or in
part, at any time prior to their maturity at a redemption price equal to the
principal amount, plus accrued and unpaid interest and a make-whole
premium. ONEOK may redeem the notes due 2019 and 2028 (6.5 percent),
in whole or in part, at any time prior to their maturity at a redemption price
equal to the principal amount, plus accrued and unpaid interest. The
redemption price will never be less than 100 percent of the principal amount of
the respective note plus accrued and unpaid interest to the redemption
date. The notes due 2011, 2015, 2019, 2028 and 2035 are senior
unsecured obligations, ranking equally in right of payment with all of ONEOK’s
existing and future unsecured senior indebtedness.
The
indentures governing ONEOK Partners’ senior notes due 2011 include an event of
default upon acceleration of other indebtedness of $25 million or more, and the
indentures governing the senior notes due 2012, 2016, 2019, 2036 and 2037
include an event of default upon the acceleration of other indebtedness of $100
million or more that would be triggered by such an offer to
repurchase. Such events of default would entitle the trustee or the
holders of 25 percent in aggregate principal amount of the outstanding senior
notes due 2011, 2012, 2016, 2019, 2036 and 2037 to declare those notes
immediately due and payable in full.
ONEOK
Partners may redeem the notes due 2012, 2016, 2019, 2036 and 2037, in whole or
in part, at any time prior to their maturity at a redemption price equal to the
principal amount, plus accrued and unpaid interest and a make-whole
premium. The redemption price will never be less than 100 percent of
the principal amount of the respective note plus accrued and unpaid interest to
the redemption date. The notes due 2012, 2016, 2019, 2036 and 2037
are senior unsecured obligations, ranking equally in right of payment with all
of ONEOK Partners’ existing and future unsecured senior indebtedness, and
effectively junior to all of the existing and future debt and other liabilities
of any non-guarantor subsidiaries, and are nonrecourse to ONEOK.
ONEOK Partners’ Equity
Issuance - In February 2010, ONEOK Partners completed an underwritten
public offering of 5,500,900 common units, including the partial exercise by the
underwriters of their over-allotment option, at a public offering price of
$60.75 per common unit, generating net proceeds of approximately $322.7
million. In conjunction with the offering, ONEOK Partners GP contributed
$6.8 million in order to maintain its 2 percent general partner interest.
ONEOK Partners used the proceeds from the sale of common units and the general
partner contribution to repay borrowings under the ONEOK Partners Credit
Agreement and for general partnership purposes. As a result of these
transactions, we hold a 42.8 percent aggregate equity interest in ONEOK
Partners.
Capital Expenditures - ONEOK’s
and ONEOK Partners’ capital expenditures are financed through operating cash
flows, short- and long-term debt and the issuance of equity. Capital
expenditures were $179.7 million and $407.6 million for the six months ended
June 30, 2010 and 2009, respectively. Of these amounts, ONEOK
Partners’ capital expenditures were $98.7 million and $321.9 million for the six
months ended June 30, 2010 and 2009, respectively.
The
following table sets forth our 2010 projected capital expenditures, excluding
AFUDC:
2010
Projected Capital Expenditures
|
||||
(Millions
of dollars)
|
||||
ONEOK
Partners
|
$ |
477
|
||
Distribution
|
216
|
|||
Other
|
23
|
|||
Total projected
capital expenditures
|
$ |
716
|
Overland Pass Pipeline Company
- Overland Pass Pipeline Company is a joint venture between ONEOK Partners and
Williams Partners L.P. (Williams). A subsidiary of ONEOK Partners
owns 99 percent of the joint venture and operates the pipeline. In July
2010, ONEOK Partners received notification that Williams elected to exercise its
option to increase its ownership in Overland Pass Pipeline Company to 50 percent
from 1 percent. The purchase price, as determined in accordance with the
joint venture’s limited liability company agreement, is estimated to be
approximately $425 million. The transaction is expected to be completed
during the third quarter of 2010, subject to obtaining the necessary regulatory
approvals. Upon closing of the transaction and as long as Williams owns at
least 50 percent of Overland Pass Pipeline Company, Williams will have the
option to become operator. ONEOK Partners expects to use the proceeds
from the transaction to repay short-term debt and to fund its recently announced
capital projects.
50
Investment in Northern Border
Pipeline - Northern Border Pipeline anticipates requiring an
additional equity contribution of approximately $102 million from its partners
in 2011, of which ONEOK Partners’ share will be approximately $51 million based
on its 50 percent equity interest.
Credit Ratings - ONEOK’s and
ONEOK Partners’ long-term debt credit ratings as of June 30, 2010, are shown in
the table below:
ONEOK
|
ONEOK
Partners
|
||||
Rating
Agency
|
Rating
|
Outlook
|
Rating
|
Outlook
|
|
Moody’s
|
Baa2
|
Stable
|
Baa2
|
Stable
|
|
S&P
|
BBB
|
Stable
|
BBB
|
Stable
|
ONEOK’s
and ONEOK Partners’ commercial paper are rated Prime-2 by Moody’s and A2 by
S&P. ONEOK’s and ONEOK Partners’ credit ratings, which are
currently investment grade, may be affected by a material change in financial
ratios or a material event affecting the business. The most common
criteria for assessment of credit ratings are the debt-to-capital ratio,
business risk profile, pretax and after-tax interest coverage, and
liquidity. ONEOK and ONEOK Partners do not currently anticipate their
respective credit ratings to be downgraded. However, if ONEOK’s or
ONEOK Partners’ credit ratings were downgraded, the interest rates, as
applicable, on ONEOK’s and ONEOK Partners’ commercial paper borrowings and
borrowings under the ONEOK Credit Agreement or the ONEOK Partners Credit
Agreement would increase, and ONEOK or ONEOK Partners could potentially lose
access to the commercial paper market. In the event that ONEOK is
unable to borrow funds under its commercial paper program and there has not been
a material adverse change in its business, ONEOK would continue to have access
to the ONEOK Credit Agreement, which expires in July 2011. In the
event that ONEOK Partners is unable to borrow funds under its commercial paper
program and there has not been a material adverse change in its business, ONEOK
Partners would continue to have access to the ONEOK Partners Credit Agreement,
which expires in March 2012. An adverse rating change alone is not a
default under the ONEOK Credit Agreement or the ONEOK Partners Credit
Agreement. See additional discussion about our credit ratings under
“Long-term Financing.”
Our
Energy Services segment relies upon the investment-grade credit rating of
ONEOK’s senior unsecured long-term debt to reduce its collateral
requirements. If ONEOK’s credit ratings were to decline below
investment grade, our ability to participate in energy marketing and trading
activities could be significantly limited. Without an
investment-grade rating, we may be required to fund margin requirements with our
counterparties with cash, letters of credit or other negotiable
instruments. At June 30, 2010, ONEOK could have been required to fund
approximately $3.0 million in margin requirements related to financial contracts
upon such a downgrade. A decline in ONEOK’s credit rating below
investment grade may also significantly impact other business
segments.
Other
than the margin requirements for our Energy Services segment described above, we
have determined that we do not have significant exposure to rating triggers
under ONEOK’s or ONEOK Partners’ trust indentures, building leases, equipment
leases and other various contracts. Rating triggers are defined as
provisions that would create an automatic default or acceleration of
indebtedness based on a change in our credit rating.
In the
normal course of business, ONEOK’s and ONEOK Partners’ counterparties provide
secured and unsecured credit. In the event of a downgrade in ONEOK’s
or ONEOK Partners’ credit ratings or a significant change in ONEOK’s or ONEOK
Partners’ counterparties’ evaluation of our creditworthiness, ONEOK or ONEOK
Partners could be required to provide additional collateral in the form of cash,
letters of credit or other negotiable instruments as a condition of continuing
to conduct business with such counterparties.
Commodity Prices - We are
subject to commodity price volatility. Significant fluctuations in
commodity prices may impact our overall liquidity due to the impact commodity
price changes have on our cash flows from operating activities, including the
impact on working capital for NGLs and natural gas held in storage, margin
requirements and certain energy-related receivables. We believe that
ONEOK’s and ONEOK Partners’ available credit and cash and cash equivalents are
adequate to meet liquidity requirements associated with commodity price
volatility. See discussion beginning on page 56 under “Commodity
Price Risk” in Item 3, Quantitative and Qualitative Disclosures about Market
Risk, for information on our hedging activities.
Pension and Postretirement Benefit
Plans - Information about our pension and postretirement benefits plans
is included in Note K of the Notes to Consolidated Financial Statements in our
Annual Report. See Note G of the Notes to Consolidated Financial
Statements in this Quarterly Report for additional information.
51
CASH
FLOW ANALYSIS
We use
the indirect method to prepare our Consolidated Statements of Cash
Flows. Under this method, we reconcile net income to cash flows
provided by operating activities by adjusting net income for those items that
impact net income but may not result in actual cash receipts or payments during
the period. These reconciling items include depreciation and
amortization, allowance for equity funds used during construction, gain or loss
on sale of assets, deferred income taxes, equity earnings from investments,
distributions received from unconsolidated affiliates, deferred income taxes,
share-based compensation expense, allowance for doubtful accounts, and changes
in our assets and liabilities not classified as investing or financing
activities.
The
following table sets forth the changes in cash flows by operating, investing and
financing activities for the periods indicated:
Six
Months Ended
|
Variances
|
|||||||||||||||
June
30,
|
2010
vs. 2009
|
|||||||||||||||
2010
|
2009
|
Increase
(Decrease)
|
||||||||||||||
(Millions
of dollars)
|
||||||||||||||||
Total
cash provided by (used in):
|
||||||||||||||||
Operating
activities
|
$ | 591.1 | $ | 1,075.9 | $ | (484.8 | ) | (45 | %) | |||||||
Investing
activities
|
(169.9 | ) | (380.2 | ) | 210.3 | 55 | % | |||||||||
Financing
activities
|
(347.4 | ) | (1,158.7 | ) | 811.3 | 70 | % | |||||||||
Change in cash and
cash equivalents
|
73.8 | (463.0 | ) | 536.8 | * | |||||||||||
Cash and cash
equivalents at beginning of period
|
29.4 | 510.0 | (480.6 | ) | (94 | %) | ||||||||||
Cash and cash
equivalents at end of period
|
$ | 103.2 | $ | 47.0 | $ | 56.2 | * | |||||||||
*
Percentage change is greater than 100 percent.
|
Operating Cash Flows -
Operating cash flows are affected by earnings from our business
activities. We provide services to producers and consumers of natural
gas, condensate and NGLs. Changes in commodity prices and demand for
our services or products, whether because of general economic conditions,
changes in demand for the end products that are made with our products or
increased competition from other service providers, could affect our earnings
and operating cash flows.
Cash
flows from operating activities, before changes in operating assets and
liabilities, were $480.7 million for the six months ended June 30, 2010,
compared with $416.9 million for the same period in 2009. The
increase was due primarily to changes in operating income discussed in
“Consolidated Operations” in Financial Results and Operating Information
beginning on page 38.
The
changes in operating assets and liabilities increased operating cash flows
$110.4 million for the six months ended June 30, 2010, compared with an increase
of $659.0 million for the same period in 2009, primarily as a result of the
following:
· the
impact of commodity prices on our operating assets and liabilities;
· the
changes in volumes of commodities in storage; and
·
|
the
timing of payments for purchases of commodities and other expenses
resulting in decreased accounts payable; offset partially
by
|
·
|
the
timing of cash receipts from our revenues resulting in decreased accounts
receivable.
|
Investing Cash Flows - Cash
used in investing activities decreased for the six months ended June 30, 2010,
compared with the same period in 2009, due primarily to reduced capital
expenditures as a result of the completion of ONEOK Partners’ capital projects
included under Item 7, Management’s Discussion and Analysis of Financial
Condition and Results of Operations, “Capital Projects,” in our Annual
Report.
Financing Cash Flows - Cash
used in financing activities decreased for the six months ended June 30, 2010,
compared with the same period last year, due primarily to the
following:
·
|
Net
repayments of notes payable were $201.9 million during the first six
months of 2010, compared with net repayments of $1.6 billion for the same
period in 2009;
|
·
|
In
March 2009, ONEOK Partners completed an underwritten public offering of
senior notes and received proceeds of approximately $498.3 million, net of
discounts but before offering expenses. ONEOK Partners used the
net proceeds from the notes to repay borrowings under the ONEOK Partners
Credit Agreement;
|
·
|
In
June 2010, ONEOK Partners repaid $250.0 million of maturing long-term debt
with available cash and short-term borrowings. In February
2009, ONEOK repaid $100.0 million of maturing long-term debt with
available cash and short-term
borrowings;
|
52
·
|
The
change in net proceeds generated from ONEOK Partners’ common unit
offerings for the six months ended June 30, 2010, compared with the same
period last year, due primarily to the
following:
|
-
|
In
February 2010, ONEOK Partners’ common unit offering generated net proceeds
of approximately $322.7 million. In addition, ONEOK Partners GP
contributed $6.8 million in order to maintain its 2 percent general
partner interest. ONEOK Partners used the proceeds to repay
borrowings under the ONEOK Partners Credit Agreement and for general
partnership purposes;
|
-
|
In
June 2009, ONEOK Partners’ common unit offering generated net proceeds of
approximately $220.5 million. In addition, ONEOK Partners GP
contributed $4.7 million in order to maintain its 2 percent general
partner interest. ONEOK Partners used the proceeds to repay
borrowings under the ONEOK Partners Credit Agreement and for general
partnership purposes;
|
·
|
ONEOK’s
dividends paid were $93.5 million and $84.2 million for the six months
ended June 30, 2010 and 2009, respectively. Dividends paid were
$0.88 per share and $0.80 per share for the six months ended June 30, 2010
and 2009, respectively; and
|
·
|
ONEOK
Partners’ distributions paid to noncontrolling interests in consolidated
subsidiaries were $126.1 million and $105.3 million for the six months
ended June 30, 2010 and 2009, respectively. Distributions paid
to limited partners by ONEOK Partners were $2.21 per unit and $2.16 per
unit for the six months ended June 30, 2010 and 2009,
respectively.
|
ENVIRONMENTAL
AND SAFETY MATTERS
Additional
information about our environmental matters is included in Note H of the
Notes to Consolidated Financial Statements in this Quarterly
Report.
Pipeline Safety - We are
subject to Pipeline and Hazardous Materials Safety Administration regulations,
including integrity management regulations. The Pipeline Safety
Improvement Act of 2002 requires pipeline companies to perform integrity
assessments on pipeline segments that pass through densely populated areas or
near specifically designated high consequence areas. We are in
compliance with all material requirements associated with the various pipeline
safety regulations. We cannot provide assurance that existing
pipeline safety regulations will not be revised or interpreted in a different
manner or that new regulations will not be adopted that could result in
increased compliance costs or additional operating restrictions.
Air and Water Emissions - The
Clean Air Act, the Clean Water Act and analogous state laws impose restrictions
and controls regarding the discharge of pollutants into the air and water in the
United States. Under the Clean Air Act, a federally enforceable
operating permit is required for sources of significant air
emissions. We may be required to incur certain capital expenditures
for air pollution-control equipment in connection with obtaining or maintaining
permits and approvals for sources of air emissions. The Clean Water
Act imposes substantial potential liability for the removal of pollutants
discharged to waters of the United States and remediation of waters affected by
such discharge. We are in compliance with all material requirements
associated with the various air and water quality regulations.
The
United States Congress is actively considering legislation to reduce greenhouse
gas emissions, including carbon dioxide and methane. In addition,
other federal, state and regional initiatives to regulate greenhouse gas
emissions are under way. We are monitoring federal and state
legislation to assess the potential impact on our operations. We
estimate our direct greenhouse gas emissions annually as we collect all
applicable greenhouse gas emission data for the previous year. Our
most recent estimate for ONEOK and ONEOK Partners indicates that our 2009
emissions were less than 4.5 million metric tons of carbon dioxide equivalents
on an annual basis. We will continue efforts to improve our ability
to quantify our direct greenhouse gas emissions and will report such emissions
as required by the EPA’s Mandatory Greenhouse Gas Reporting rule adopted in
September 2009. The rule requires greenhouse gas emissions reporting
for affected facilities on an annual basis, beginning with our 2010 emissions
report that will be due in March 2011, and will require us to track the emission
equivalents for the gas delivered by us to our distribution customers and
emission equivalents for all NGLs delivered to customers of ONEOK Partners.
Also, the EPA has recently released a proposed subpart to the Mandatory
Greenhouse Gas Reporting Rule that will require the reporting of vented and
fugitive emissions of methane from our facilities. The new
requirements are proposed to begin in January 2011, with the first reporting of
fugitive emissions due March 31, 2012. We do not expect the cost to
gather this emission data to have a material impact on our results of
operations, financial position or cash flows. At this time, no
legislation has been enacted that assesses any costs, fees or expenses on any of
these emissions.
In May
2010, the EPA finalized the “Tailoring Rule” that will regulate greenhouse gas
emissions at new or modified facilities that meet certain
criteria. Affected facilities will be required to review best
available control technology, conduct air-quality analysis, impact analysis and
public reviews with respect to such emissions. The rule will be
phased in beginning January 2011 and, at current emission threshold levels, will
have a minimal impact on our existing facilities. The EPA has stated
it
53
will
consider lowering the threshold levels over the next five years, which could
increase the impact on our existing facilities. However, potential
costs, fees or expenses associated with the potential adjustments are
unknown.
In
addition, the EPA issued a rule on air-quality standards, “National Emission
Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion
Engines,” also known as RICE NESHAP, scheduled to be adopted in early
2013. The rule will require capital expenditures over the next three
years for the purchase and installation of new emissions-control
equipment. We do not expect these expenditures to have a material impact
on our results of operations, financial position or cash flows.
Superfund - The Comprehensive
Environmental Response, Compensation and Liability Act, also known as CERCLA or
Superfund, imposes liability, without regard to fault or the legality of the
original act, on certain classes of persons who contributed to the release of a
hazardous substance into the environment. These persons include the
owner or operator of a facility where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances found at the
facility. Under CERCLA, these persons may be liable for the costs of
cleaning up the hazardous substances released into the environment, damages to
natural resources and the costs of certain health studies.
Chemical Site Security - The
United States Department of Homeland Security (Homeland Security) released an
interim rule in April 2007 that requires companies to provide reports on sites
where certain chemicals, including many hydrocarbon products, are
stored. We completed the Homeland Security assessments, and our
facilities were subsequently assigned, on a preliminary basis, one of four
risk-based tiers ranging from high (Tier 1) to low (Tier 4) risk, or not tiered
at all due to low risk. To date, four of our facilities have been
given a Tier 4 rating. Facilities receiving a Tier 4 rating are
required to complete Site Security Plans and possible physical security
enhancements. We do not expect the Site Security Plans and possible
security enhancements cost to have a material impact on our results of
operations, financial position or cash flows.
Pipeline Security - Homeland
Security’s Transportation Security Administration, along with the United States
Department of Transportation, has completed a review and inspection of our
“critical facilities” and identified no material security issues.
Environmental Footprint - Our
environmental and climate change strategy focuses on taking steps to minimize
the impact of our operations on the environment. These strategies
include: (i) developing and maintaining an accurate greenhouse gas emissions
inventory, according to new rules issued by the EPA; (ii) improving the
efficiency of our various pipelines, natural gas processing facilities and
natural gas liquids fractionation facilities; (iii) following developing
technologies for emission control; (iv) following developing technologies to
capture carbon dioxide to keep it from reaching the atmosphere; and (v)
analyzing options for future energy investment.
We
continue to focus on maintaining low rates of lost-and-unaccounted-for natural
gas through expanded implementation of best practices to limit the release of
natural gas during pipeline and facility maintenance and
operations. Our most recent calculation of our annual
lost-and-unaccounted-for natural gas, for all of our business operations, is
less than 1 percent of total throughput.
FORWARD-LOOKING
STATEMENTS
Some of
the statements contained and incorporated in this Quarterly Report are
forward-looking statements within the meaning of Section 27A of the Securities
Act and Section 21E of the Exchange Act. The forward-looking
statements relate to our anticipated financial performance, management’s plans
and objectives for our future operations, our business prospects, the outcome of
regulatory and legal proceedings, market conditions and other
matters. We make these forward-looking statements in reliance on the
safe harbor protections provided under the Private Securities Litigation Reform
Act of 1995. The following discussion is intended to identify
important factors that could cause future outcomes to differ materially from
those set forth in the forward-looking statements.
Forward-looking
statements include the items identified in the preceding paragraph, the
information concerning possible or assumed future results of our operations and
other statements contained or incorporated in this Quarterly Report identified
by words such as “anticipate,” “estimate,” “expect,” “project,” “intend,”
“plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,”
“continue,” “might,” “potential,” “scheduled,” and other words and terms of
similar meaning.
One
should not place undue reliance on forward-looking statements, which are
applicable only as of the date of this Quarterly Report. Known and
unknown risks, uncertainties and other factors may cause our actual results,
performance or achievements to be materially different from any future results,
performance or achievements expressed or implied by forward-looking
statements. Those factors may affect our operations, markets,
products, services and prices. In addition to any assumptions and
other factors referred to specifically in connection with the forward-looking
statements, factors that
54
could
cause our actual results to differ materially from those contemplated in any
forward-looking statement include, among others, the following:
·
|
the
effects of weather and other natural phenomena on our operations,
including energy sales and demand for our services and energy
prices;
|
·
|
competition
from other United States and foreign energy suppliers and transporters, as
well as alternative forms of energy, including, but not limited to, solar
power, wind power, geothermal energy and biofuels such as ethanol and
biodiesel;
|
·
|
the
status of deregulation of retail natural gas
distribution;
|
·
|
the
capital intensive nature of our
businesses;
|
·
|
the
profitability of assets or businesses acquired or constructed by
us;
|
·
|
our
ability to make cost-saving changes in
operations;
|
·
|
risks
of marketing, trading and hedging activities, including the risks of
changes in energy prices or the financial condition of our
counterparties;
|
·
|
the
uncertainty of estimates, including accruals and costs of environmental
remediation;
|
·
|
the
timing and extent of changes in energy commodity
prices;
|
·
|
the
effects of changes in governmental policies and regulatory actions,
including changes with respect to income and other taxes, environmental
compliance, climate change initiatives, and authorized rates of recovery
of gas and gas transportation
costs;
|
·
|
the
impact on drilling and production by factors beyond our control, including
the demand for natural gas and crude oil; producers’ desire and ability to
obtain necessary permits; reserve performance; and capacity constraints on
the pipelines that transport crude oil, natural gas and NGLs from
producing areas and our facilities;
|
·
|
changes
in demand for the use of natural gas because of market conditions caused
by concerns about global warming;
|
·
|
the
impact of unforeseen changes in interest rates, equity markets, inflation
rates, economic recession and other external factors over which we have no
control, including the effect on pension expense and funding resulting
from changes in stock and bond market
returns;
|
·
|
our
indebtedness could make us vulnerable to general adverse economic and
industry conditions, limit our ability to borrow additional funds and/or
place us at competitive disadvantages compared with our competitors that
have less debt, or have other adverse
consequences;
|
·
|
actions
by rating agencies concerning the credit ratings of ONEOK and ONEOK
Partners;
|
·
|
the
results of administrative proceedings and litigation, regulatory actions
and receipt of expected clearances involving the OCC, KCC, Texas
regulatory authorities or any other local, state or federal regulatory
body, including the FERC;
|
·
|
our
ability to access capital at competitive rates or on terms acceptable to
us;
|
·
|
risks
associated with adequate supply to our gathering, processing,
fractionation and pipeline facilities, including production declines that
outpace new drilling;
|
·
|
the
risk that material weaknesses or significant deficiencies in our internal
controls over financial reporting could emerge or that minor problems
could become significant;
|
·
|
the
impact and outcome of pending and future
litigation;
|
·
|
the
ability to market pipeline capacity on favorable terms, including the
effects of:
|
-
|
future
demand for and prices of natural gas and
NGLs;
|
-
|
competitive
conditions in the overall energy
market;
|
-
|
availability
of supplies of Canadian and United States natural gas;
and
|
-
|
availability
of additional storage capacity;
|
·
|
performance
of contractual obligations by our customers, service providers,
contractors and shippers;
|
·
|
the
timely receipt of approval by applicable governmental entities for
construction and operation of our pipeline and other projects and required
regulatory clearances;
|
·
|
our
ability to acquire all necessary permits, consents or other approvals in a
timely manner, to promptly obtain all necessary materials and supplies
required for construction, and to construct gathering, processing,
storage, fractionation and transportation facilities without labor or
contractor problems;
|
·
|
the
mechanical integrity of facilities
operated;
|
·
|
demand
for our services in the proximity of our
facilities;
|
·
|
our
ability to control operating costs;
|
·
|
adverse
labor relations;
|
·
|
acts
of nature, sabotage, terrorism or other similar acts that cause damage to
our facilities or our suppliers’ or shippers’
facilities;
|
55
·
|
economic
climate and growth in the geographic areas in which we do
business;
|
·
|
the
risk of a prolonged slowdown in growth or decline in the U.S. economy or
the risk of delay in growth recovery in the United States economy,
including liquidity risks in United States credit
markets;
|
·
|
the
impact of recently issued and future accounting updates and other changes
in accounting policies;
|
·
|
the
possibility of future terrorist attacks or the possibility or occurrence
of an outbreak of, or changes in, hostilities or changes in the political
conditions in the Middle East and
elsewhere;
|
·
|
the
risk of increased costs for insurance premiums, security or other items as
a consequence of terrorist attacks;
|
·
|
risks
associated with pending or possible acquisitions and dispositions,
including our ability to finance or integrate any such acquisitions and
any regulatory delay or conditions imposed by regulatory bodies in
connection with any such acquisitions and
dispositions;
|
·
|
the
possible loss of gas distribution franchises or other adverse effects
caused by the actions of
municipalities;
|
·
|
the
impact of unsold pipeline capacity being greater or less than
expected;
|
·
|
the
ability to recover operating costs and amounts equivalent to income taxes,
costs of property, plant and equipment and regulatory assets in our state
and FERC-regulated rates;
|
·
|
the
composition and quality of the natural gas and NGLs we gather and process
in our plants and transport on our
pipelines;
|
·
|
the
efficiency of our plants in processing natural gas and extracting and
fractionating NGLs;
|
·
|
the
impact of potential impairment
charges;
|
·
|
the
risk inherent in the use of information systems in our respective
businesses, implementation of new software and hardware, and the impact on
the timeliness of information for financial
reporting;
|
·
|
our
ability to control construction costs and completion schedules of our
pipelines and other projects;
and
|
·
|
the
risk factors listed in the reports we have filed and may file with the
SEC, which are incorporated by
reference.
|
These
factors are not necessarily all of the important factors that could cause actual
results to differ materially from those expressed in any of our forward-looking
statements. Other factors could also have material adverse effects on
our future results. These and other risks are described in greater
detail in Item 1A, Risk Factors, in our Quarterly Report. All
forward-looking statements attributable to us or persons acting on our behalf
are expressly qualified in their entirety by these factors. Other
than as required under securities laws, we undertake no obligation to update
publicly any forward-looking statement whether as a result of new information,
subsequent events or change in circumstances, expectations or
otherwise.
ITEM
3. QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our
quantitative and qualitative disclosures about market risk are consistent with
those discussed in Part II, Item 7A, Quantitative and Qualitative Disclosures
About Market Risk in our Annual Report.
COMMODITY
PRICE RISK
See
Note C of the Notes to Consolidated Financial Statements and the
discussion under ONEOK Partners’ “Commodity Price Risk” in Item 2, Management’s
Discussion and Analysis of Financial Condition and Results of Operations, in
this Quarterly Report for information on our hedging activities.
56
Energy
Services
Fair Value Component of Energy
Marketing and Risk Management Assets and Liabilities - The following
table sets forth the fair value component of our energy marketing and risk
management assets and liabilities, excluding $117.1 million of net assets from
derivative instruments designated as either fair value or cash flow hedges at
June 30, 2010, and $0.4 million of deferred option premiums at June 30,
2010:
Fair
Value Component of Energy Marketing and Risk Management Assets and
Liabilities
|
||||
(Thousands of dollars)
|
||||
Net
fair value of derivatives outstanding at December 31, 2009
|
$
|
2,725
|
||
Derivatives
reclassified or otherwise settled during the period
|
(3,675
|
)
|
||
Fair value of new
derivatives entered into during the period
|
5,231
|
|||
Other changes in
fair value
|
1,571
|
|||
Net
fair value of derivatives outstanding at June 30, 2010 (a)
|
$
|
5,852
|
||
(a) - The maturities of
derivatives are based on injection and withdrawal periods from April
through March, which
is consistent with our business strategy. The maturities
are as follows: $2.9 million matures through
March 2011 and $3.0 million matures through March 2012
.
|
The
change in the net fair value of derivatives outstanding includes the effect of
settled energy contracts and current period changes resulting primarily from
newly originated transactions and the impact of market movements on the fair
value of energy marketing and risk management assets and
liabilities.
For
further discussion of derivative instruments and fair value measurements, see
the “Critical Accounting Estimates” section of Item 7, Management’s Discussion
and Analysis of Financial Condition and Results of Operations in our Annual
Report. Also, see Notes B and C of the Notes to
Consolidated Financial Statements in this Quarterly Report.
Value-at-Risk (VAR) Disclosure of
Market Risk - We measure commodity
price risk in our Energy Services segment using a VAR methodology, which
estimates the expected maximum loss of our portfolio over a specified time
horizon within a given confidence interval. Our VAR calculations are
based on the Monte Carlo approach. The quantification of commodity
price risk using VAR provides a consistent measure of risk across diverse energy
markets and products with different risk factors in order to set overall risk
tolerance and to determine risk thresholds. The use of this
methodology requires a number of key assumptions, including the selection of a
confidence level and the holding period to liquidation. Inputs to the
calculation include prices, volatilities, positions, instrument valuations and
the variance-covariance matrix. Historical data is used to estimate
our VAR with more weight given to recent data, which is considered a more
relevant predictor of immediate future commodity market movements. We
rely on VAR to determine the potential reduction in the portfolio values arising
from changes in market conditions over a defined period. While
management believes that the referenced assumptions and approximations are
reasonable, no uniform industry methodology exists for estimating
VAR. Different assumptions and approximations could produce
materially different VAR estimates.
Our VAR
exposure represents an estimate of potential losses that would be recognized due
to adverse commodity price movements in our Energy Services segment’s portfolio
of derivative financial instruments, physical commodity contracts, leased
transport, storage capacity contracts and natural gas in storage. A
one-day time horizon and a 95 percent confidence level are used in our VAR
data. Actual future gains and losses will differ from those estimated
by the VAR calculation based on actual fluctuations in commodity prices,
operating exposures and timing thereof, and the changes in our derivative
financial instruments, physical contracts and natural gas in
storage. VAR information should be evaluated in light of these
assumptions and the methodology’s other limitations.
The
potential impact on our future earnings was $6.5 million and $6.9 million at
June 30, 2010 and 2009, respectively. The following table sets forth
the average, high and low VAR calculations for the periods
indicated:
Three
Months Ended
|
Six
Months Ended
|
|||||||||||||||
June
30,
|
June
30,
|
|||||||||||||||
Value-at-Risk
|
2010
|
2009
|
2010
|
2009
|
||||||||||||
(Millions
of dollars)
|
||||||||||||||||
Average
|
$ | 7.7 | $ | 9.0 | $ | 7.0 | $ | 9.6 | ||||||||
High
|
$ | 9.1 | $ | 13.0 | $ | 9.6 | $ | 14.1 | ||||||||
Low
|
$ | 5.0 | $ | 6.5 | $ | 3.9 | $ | 6.2 |
57
ITEM
4. CONTROLS
AND PROCEDURES
Quarterly Evaluation of Disclosure
Controls and Procedures - As of the end of the period covered by this
report, our Chief Executive Officer (Principal Executive Officer) and Chief
Financial Officer (Principal Financial Officer) evaluated the effectiveness of
our disclosure controls and procedures as defined in Rules 13a-15(e) and
15d-15(e) of the Exchange Act. Disclosure controls and procedures
include, without limitation, controls and procedures designed to ensure that
information required to be disclosed by us in the reports that we file or submit
under the Exchange Act is accumulated and communicated to management, including
our principal executive and principal financial officers, as appropriate to
allow timely decisions regarding required disclosure. Based on their
evaluation, they concluded that as of June 30, 2010, our disclosure controls and
procedures were effective in ensuring that the information required to be
disclosed by us in the reports we file or submit under the Exchange Act is
recorded, processed, summarized and reported within the time periods specified
in the SEC’s rules and forms.
Changes in Internal Controls Over
Financial Reporting - There have been no changes in our
internal controls over financial reporting (as defined in Rule 13a-15(f) and
15d-15(f) under the Exchange Act) during the second quarter ended June 30 2010,
that have materially affected, or are reasonably likely to materially affect,
our internal control over financial reporting.
PART
II - OTHER INFORMATION
ITEM
1. LEGAL
PROCEEDINGS
Additional
information about our legal proceedings is included under Part I, Item 3, Legal
Proceedings, in our Annual Report and in our March 31, 2010 Quarterly
Report.
Gas Index
Pricing Litigation - As previously reported,
we, our subsidiary ONEOK Energy Services Company, L.P. (“OESC”) and one other
affiliate are defending, either individually or together, against multiple
lawsuits claiming damages resulting from the alleged market manipulation or
false reporting of prices to gas index publications by us and
others. On June 4, 2010, the United States District Court for the
District of Nevada, in the MDL-1566 multi-district proceedings, denied the
defendants’ motion to dismiss the NewPage Wisconsin System v. CMS
Energy Resource Management Company, et al., case, and granted the
plaintiffs’ motion to consolidate this case with the Arandell Corporation, et al. v. Xcel
Energy, Inc., et al., case. The time for seeking further
appellate review of the decision of the Tennessee Supreme Court dismissing the
plaintiffs’ claims in the Leggett case expired on July
22, 2010. Therefore, the dismissal is now final, formally concluding the
case. We continue to vigorously defend against the claims involved in
all of the cases.
ITEM
1A. RISK
FACTORS
Our
investors should consider the risks set forth in Part I, Item 1A, Risk Factors
of our Annual Report that could affect us and our business. Although
we have tried to discuss key factors, our investors need to be aware that other
risks may prove to be important in the future. New risks may emerge
at any time, and we cannot predict such risks or estimate the extent to which
they may affect our financial performance. Investors should carefully
consider the discussion of risks and the other information included or
incorporated by reference in this Quarterly Report, including “Forward-Looking
Statements,” which are included in Part I, Item 2, Management’s Discussion and
Analysis of Financial Condition and Results of Operations.
58
ITEM
2. UNREGISTERED
SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Issuer
Purchases of Equity Securities
The
following table sets forth information relating to our purchases of our common
stock for the periods indicated:
Period
|
Total
Number of Shares
Purchased
|
Average
Price
Paid
per Share
|
Total
Number of
Shares
Purchased
as
Part of Publicly
Announced
Plans or
Programs
|
Maximum
Number (or
Approximate
Dollar Value)
of
Shares (or Units) that
May
Be Purchased Under
the
Plans or Programs
|
|||||||
April
1-30, 2010
|
10,373
|
(a),
(b)
|
$30.05
|
-
|
-
|
||||||
May
1-31, 2010
|
80,161
|
(a),
(b)
|
$17.28
|
-
|
-
|
||||||
June
1-30, 2010
|
-
|
$0.00
|
-
|
-
|
|||||||
Total
|
90,534
|
$18.74
|
-
|
-
|
|||||||
(a)
- Includes shares withheld pursuant to attestation of ownership and deemed
tendered to us in connection with the exercise
|
|||||||||||
of stock options under the ONEOK, Inc. Long-Term Incentive Plan, as
follows:
|
|||||||||||
10,369
shares for the period of April 1-30, 2010
|
|||||||||||
80,132
shares for the period of May 1-31, 2010
|
|||||||||||
(b)
- Includes shares repurchased directly from employees, pursuant to our
Employee Stock Award Program, as follows:
|
|||||||||||
4
shares for the period April 1-30, 2010
|
|||||||||||
29
shares for the period May 1-31, 2010
|
ITEM
3. DEFAULTS
UPON SENIOR SECURITIES
Not
Applicable.
ITEM
4. (REMOVED
AND RESERVED)
Not
Applicable.
ITEM
5. OTHER
INFORMATION
Not
Applicable.
ITEM
6. EXHIBITS
Readers
of this report should not rely on or assume the accuracy of any representation
or warranty or the validity of any opinion contained in any agreement filed as
an exhibit to this Quarterly Report, because such representation, warranty or
opinion may be subject to exceptions and qualifications contained in separate
disclosure schedules, may represent an allocation of risk between parties in the
particular transaction, may be qualified by materiality standards that differ
from what may be viewed as material for securities law purposes, or may no
longer continue to be true as of any given date. All exhibits attached to
this Quarterly Report are included for the purpose of complying with
requirements of the SEC. Other than the certifications made by our
officers pursuant to the Sarbanes-Oxley Act of 2002 included as exhibits to this
Quarterly Report, all exhibits are included only to provide information to
investors regarding their respective terms and should not be relied upon as
constituting or providing any factual disclosures about us, any other persons,
any state of affairs or other matters.
59
The
following exhibits are filed as part of this Quarterly Report:
Exhibit
No. Exhibit
Description
10.1
|
Commercial
Paper Dealer Agreement between ONEOK Partners, L.P. and Citigroup Global
Markets Inc. dated
as of June 16, 2010 (incorporated by reference to Exhibit 10.1
to
ONEOK Inc.’s Current Report on Form
8-K filed on June 22, 2010).
|
|
10.2
|
Commercial
Paper Dealer Agreement between ONEOK Partners, L.P. and Banc of America
Securities LLC dated as of June 16, 2010 (incorporated by reference to
Exhibit 10.2 to ONEOK Inc.’s Current Report on Form 8-K filed on June 22,
2010).
|
|
10.3
|
Commercial
Paper Dealer Agreement between ONEOK Partners, L.P. and SunTrust Robinson
Humphrey, Inc. dated as of June 16, 2010 (incorporated by reference to
Exhibit 10.3 to ONEOK Inc.’s Current Report on Form 8-K filed on June 22,
2010).
|
|
31.1
|
Certification
of John W. Gibson pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
|
|
31.2
|
Certification
of Curtis L. Dinan pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
|
|
32.1
|
Certification
of John W. Gibson pursuant to 18 U.S.C. Section 1350 as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant
to Rule 13a-14(b)).
|
|
32.2
|
Certification
of Curtis L. Dinan pursuant to 18 U.S.C. Section 1350 as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant
to Rule 13a-14(b)).
|
|
101.INS
|
XBRL
Instance Document
|
|
101.SCH
|
XBRL
Taxonomy Extension Schema Document
|
|
101.CAL
|
XBRL
Taxonomy Calculation Linkbase
Document
|
|
101.DEF
|
XBRL
Taxonomy Extension Definitions
Document
|
|
101.LAB
|
XBRL
Taxonomy Label Linkbase Document
|
|
101.PRE
|
XBRL
Taxonomy Presentation Linkbase
Document
|
Attached
as Exhibit 101 to this Quarterly Report are the following documents formatted in
XBRL: (i) Document and Entity Information; (ii) Consolidated Statements of
Income for the three and six months ended June 30, 2010 and 2009;
(iii) Consolidated Balance Sheets at June 30, 2010 and December 31,
2009; (iv) Consolidated Statements of Cash Flows for the six months ended
June 30, 2010 and 2009; (v) Consolidated Statement of Changes in Equity for
the six months ended June 30, 2010; (vi) Consolidated Statements of
Comprehensive Income for the three and six months ended June 30, 2010 and 2009;
and (vii) Notes to Consolidated Financial Statements.
Users of
this data are advised pursuant to Rule 401 of Regulation S-T that the
information contained in the XBRL documents is unaudited, and these XBRL
documents are not the official publicly filed consolidated financial statements
of ONEOK, Inc. The purpose of submitting these XBRL formatted
documents is to test the related format and technology, and as a result,
investors should continue to rely on the official filed version of the furnished
documents and not rely on this information in making investment
decisions.
In
accordance with Rule 402 of Regulation S-T, the XBRL related information in
Exhibit 101 to this Quarterly Report shall not be deemed to be “filed” for
purposes of Section 18 of the Exchange Act, or otherwise subject to the
liability of that section, and shall not be incorporated by reference into any
registration statement or other document filed under the Securities Act or the
Exchange Act, except as shall be expressly set forth by specific reference in
such filing. We also make available on our Web site the Interactive
Data Files submitted as Exhibit 101 to this Quarterly Report.
60
SIGNATURE
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized.
ONEOK,
Inc.
Registrant
|
||
Date: August 4,
2010
|
By:
|
/s/
Curtis L. Dinan
|
Curtis
L. Dinan
Senior
Vice President,
Chief
Financial Officer and Treasurer
(Principal
Financial Officer)
|
61