form_10-q.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 March 31, 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 April
22, 2010, the Company had 106,295,263 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 Months Ended March 31, 2010 and
2009
|
5
|
|
Consolidated
Balance Sheets - March 31, 2010 and December 31, 2009
|
6-7
|
|
Consolidated
Statements of Cash Flows - Three Months Ended March 31, 2010 and
2009
|
9
|
|
Consolidated
Statement of Shareholders’ Equity - Three Months Ended March 31,
2010
|
10-11
|
|
Consolidated
Statements of Comprehensive Income - Three Months Ended March 31, 2010 and
2009
|
12
|
|
Notes
to Consolidated Financial Statements
|
13-30
|
Item
2.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
|
31-50
|
Item
3.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
50-51
|
Item
4.
|
Controls
and Procedures
|
51
|
Part
II.
|
Other
Information
|
|
Item
1.
|
Legal
Proceedings
|
52
|
Item
1A.
|
Risk
Factors
|
52
|
Item
2.
|
Unregistered
Sales of Equity Securities and Use of Proceeds
|
53
|
Item
3.
|
Defaults
Upon Senior Securities
|
53
|
Item
4.
|
(Removed
and Reserved)
|
53
|
Item
5.
|
Other
Information
|
53
|
Item
6.
|
Exhibits
|
54
|
Signature
|
|
55
|
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.
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
|
|
XBRL.................................................................
|
eXtensible
Business Reporting
Language
|
This page
intentionally left blank.
PART
I - FINANCIAL INFORMATION
|
|
|
|
|
|
ITEM
1. FINANCIAL STATEMENTS
|
|
|
|
|
|
ONEOK,
Inc. and Subsidiaries
|
|
|
|
|
|
CONSOLIDATED STATEMENTS
OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
(Unaudited)
|
|
2010
|
|
2009
|
|
|
|
(Thousands
of dollars, except per share amounts)
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
3,923,967 |
|
$ |
2,789,827 |
|
Cost
of sales and fuel
|
|
|
3,304,648 |
|
|
2,238,416 |
|
Net
margin
|
|
|
619,319 |
|
|
551,411 |
|
Operating
expenses
|
|
|
|
|
|
|
|
Operations
and maintenance
|
|
|
180,272 |
|
|
161,719 |
|
Depreciation
and amortization
|
|
|
77,856 |
|
|
72,126 |
|
General
taxes
|
|
|
23,073 |
|
|
25,227 |
|
Total
operating expenses
|
|
|
281,201 |
|
|
259,072 |
|
Gain
(loss) on sale of assets
|
|
|
(786 |
) |
|
664 |
|
Operating
income
|
|
|
337,332 |
|
|
293,003 |
|
Equity
earnings from investments (Note J)
|
|
|
21,116 |
|
|
21,222 |
|
Allowance
for equity funds used during construction
|
|
|
247 |
|
|
9,003 |
|
Other
income
|
|
|
2,909 |
|
|
1,665 |
|
Other
expense
|
|
|
(1,053 |
) |
|
(3,944 |
) |
Interest
expense
|
|
|
(76,520 |
) |
|
(77,961 |
) |
Income
before income taxes
|
|
|
284,031 |
|
|
242,988 |
|
Income
taxes
|
|
|
(97,311 |
) |
|
(79,439 |
) |
Net
income
|
|
|
186,720 |
|
|
163,549 |
|
Less:
Net income attributable to noncontrolling interests
|
|
|
32,181 |
|
|
41,264 |
|
Net
income attributable to ONEOK
|
|
$ |
154,539 |
|
$ |
122,285 |
|
|
|
|
|
|
|
|
|
Earnings
per share of common stock (Note K)
|
|
|
|
|
|
|
|
Net
earnings per share, basic
|
|
$ |
1.46 |
|
$ |
1.16 |
|
Net
earnings per share, diluted
|
|
$ |
1.44 |
|
$ |
1.16 |
|
|
|
|
|
|
|
|
|
Average
shares of common stock (thousands)
|
|
|
|
|
|
|
|
Basic
|
|
|
106,132 |
|
|
105,162 |
|
Diluted
|
|
|
107,410 |
|
|
105,733 |
|
|
|
|
|
|
|
|
|
Dividends
declared per share of common stock
|
|
$ |
0.44 |
|
$ |
0.40 |
|
See
accompanying Notes to Consolidated Financial Statements.
|
|
|
|
|
|
|
|
ONEOK,
Inc. and Subsidiaries
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
March
31,
|
|
|
December
31,
|
|
(Unaudited)
|
|
2010
|
|
|
2009
|
|
Assets
|
|
(Thousands
of dollars)
|
|
Current
assets
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
167,433 |
|
|
$ |
29,399 |
|
Accounts
receivable, net
|
|
|
1,202,293 |
|
|
|
1,437,994 |
|
Gas
and natural gas liquids in storage
|
|
|
397,254 |
|
|
|
583,127 |
|
Commodity
imbalances
|
|
|
96,487 |
|
|
|
186,015 |
|
Energy
marketing and risk management assets (Notes B and C)
|
|
|
156,086 |
|
|
|
113,039 |
|
Other
current assets
|
|
|
89,175 |
|
|
|
238,890 |
|
Total
current assets
|
|
|
2,108,728 |
|
|
|
2,588,464 |
|
|
|
|
|
|
|
|
|
|
Property,
plant and equipment
|
|
|
|
|
|
|
|
|
Property,
plant and equipment
|
|
|
10,205,835 |
|
|
|
10,145,800 |
|
Accumulated
depreciation and amortization
|
|
|
2,411,431 |
|
|
|
2,352,142 |
|
Net
property, plant and equipment
|
|
|
7,794,404 |
|
|
|
7,793,658 |
|
|
|
|
|
|
|
|
|
|
Investments
and other assets
|
|
|
|
|
|
|
|
|
Goodwill
and intangible assets
|
|
|
1,028,643 |
|
|
|
1,030,560 |
|
Energy
marketing and risk management assets (Notes B and C)
|
|
|
22,547 |
|
|
|
23,125 |
|
Investments
in unconsolidated affiliates
|
|
|
762,435 |
|
|
|
765,163 |
|
Other
assets
|
|
|
612,435 |
|
|
|
626,713 |
|
Total
investments and other assets
|
|
|
2,426,060 |
|
|
|
2,445,561 |
|
Total
assets
|
|
$ |
12,329,192 |
|
|
$ |
12,827,683 |
|
See
accompanying Notes to Consolidated Financial Statements.
|
|
|
|
|
|
|
|
|
ONEOK,
Inc. and Subsidiaries
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
March
31,
|
|
|
December
31,
|
|
(Unaudited)
|
|
2010
|
|
|
2009
|
|
Liabilities
and shareholders' equity
|
|
(Thousands
of dollars)
|
|
Current
liabilities
|
|
|
|
|
|
|
Current
maturities of long-term debt
|
|
$ |
493,220 |
|
|
$ |
268,215 |
|
Notes
payable (Note E)
|
|
|
310,000 |
|
|
|
881,870 |
|
Accounts
payable
|
|
|
965,015 |
|
|
|
1,240,207 |
|
Commodity
imbalances
|
|
|
246,540 |
|
|
|
394,971 |
|
Energy
marketing and risk management liabilities (Notes B and C)
|
|
|
75,119 |
|
|
|
65,162 |
|
Other
current liabilities
|
|
|
581,622 |
|
|
|
488,487 |
|
Total
current liabilities
|
|
|
2,671,516 |
|
|
|
3,338,912 |
|
|
|
|
|
|
|
|
|
|
Long-term
debt, excluding current maturities
|
|
|
4,103,333 |
|
|
|
4,334,204 |
|
|
|
|
|
|
|
|
|
|
Deferred
credits and other liabilities
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
1,033,396 |
|
|
|
1,037,665 |
|
Energy
marketing and risk management liabilities (Notes B and C)
|
|
|
13,115 |
|
|
|
8,926 |
|
Other
deferred credits
|
|
|
628,191 |
|
|
|
662,514 |
|
Total
deferred credits and other liabilities
|
|
|
1,674,702 |
|
|
|
1,709,105 |
|
|
|
|
|
|
|
|
|
|
Commitments
and contingencies (Note H)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders'
equity (Note F)
|
|
|
|
|
|
|
|
|
ONEOK
shareholders' equity:
|
|
|
|
|
|
|
|
|
Common
stock, $0.01 par value:
|
|
|
|
|
|
|
|
|
authorized
300,000,000 shares; issued 122,545,085 shares and
outstanding
|
|
|
|
|
|
|
|
|
106,283,759
shares at March 31, 2010; issued 122,394,015 shares and
|
|
|
|
|
|
|
|
|
outstanding
105,906,776 shares at December 31, 2009
|
|
|
1,225 |
|
|
|
1,224 |
|
Paid-in
capital
|
|
|
1,365,591 |
|
|
|
1,322,340 |
|
Accumulated
other comprehensive loss (Note D)
|
|
|
(105,564 |
) |
|
|
(118,613 |
) |
Retained
earnings
|
|
|
1,793,548 |
|
|
|
1,685,710 |
|
Treasury
stock, at cost: 16,261,326 shares at March 31, 2010 and
|
|
|
|
|
|
|
|
|
16,487,239
shares at December 31, 2009
|
|
|
(674,103 |
) |
|
|
(683,467 |
) |
Total
ONEOK shareholders' equity
|
|
|
2,380,697 |
|
|
|
2,207,194 |
|
|
|
|
|
|
|
|
|
|
Noncontrolling
interests in consolidated subsidiaries
|
|
|
1,498,944 |
|
|
|
1,238,268 |
|
|
|
|
|
|
|
|
|
|
Total
shareholders' equity
|
|
|
3,879,641 |
|
|
|
3,445,462 |
|
Total
liabilities and shareholders' equity
|
|
$ |
12,329,192 |
|
|
$ |
12,827,683 |
|
See
accompanying Notes to Consolidated Financial Statements.
|
|
|
|
|
|
|
|
|
This page
intentionally left blank.
ONEOK,
Inc. and Subsidiaries
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
March
31,
|
|
(Unaudited)
|
|
2010
|
|
|
2009
|
|
|
(Thousands
of dollars)
|
|
Operating
activities
|
|
|
|
|
|
|
Net
income
|
|
$ |
186,720 |
|
|
$ |
163,549 |
|
Depreciation
and amortization
|
|
|
77,856 |
|
|
|
72,126 |
|
Allowance
for equity funds used during construction
|
|
|
(247 |
) |
|
|
(9,003 |
) |
Loss
(gain) on sale of assets
|
|
|
786 |
|
|
|
(664 |
) |
Equity
earnings from investments
|
|
|
(21,116 |
) |
|
|
(21,222 |
) |
Distributions
received from unconsolidated affiliates
|
|
|
21,998 |
|
|
|
25,187 |
|
Deferred
income taxes
|
|
|
19,542 |
|
|
|
23,624 |
|
Share-based
compensation expense
|
|
|
4,566 |
|
|
|
4,173 |
|
Allowance
for doubtful accounts
|
|
|
(221 |
) |
|
|
(822 |
) |
Changes
in assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
235,922 |
|
|
|
251,980 |
|
Gas
and natural gas liquids in storage
|
|
|
177,305 |
|
|
|
404,416 |
|
Accounts
payable
|
|
|
(268,987 |
) |
|
|
(311,252 |
) |
Commodity
imbalances, net
|
|
|
(58,903 |
) |
|
|
(51,317 |
) |
Unrecovered
purchased gas costs
|
|
|
98,783 |
|
|
|
42,445 |
|
Accrued
interest
|
|
|
43,133 |
|
|
|
38,623 |
|
Energy
marketing and risk management assets and liabilities
|
|
|
24,522 |
|
|
|
(32,921 |
) |
Fair
value of firm commitments
|
|
|
(23,023 |
) |
|
|
153,391 |
|
Other
assets and liabilities
|
|
|
40,081 |
|
|
|
38,545 |
|
Cash
provided by operating activities
|
|
|
558,717 |
|
|
|
790,858 |
|
Investing
activities
|
|
|
|
|
|
|
|
|
Changes
in investments in unconsolidated affiliates
|
|
|
1,334 |
|
|
|
3,362 |
|
Capital
expenditures (less allowance for equity funds used during
construction)
|
|
|
(68,273 |
) |
|
|
(243,027 |
) |
Proceeds
from sale of assets
|
|
|
563 |
|
|
|
1,083 |
|
Cash
used in investing activities
|
|
|
(66,376 |
) |
|
|
(238,582 |
) |
Financing
activities
|
|
|
|
|
|
|
|
|
Repayment
of notes payable, net
|
|
|
(571,870 |
) |
|
|
(813,300 |
) |
Repayment
of notes payable with maturities over 90 days
|
|
|
- |
|
|
|
(470,000 |
) |
Issuance
of debt, net of discounts
|
|
|
- |
|
|
|
498,325 |
|
Long-term
debt financing costs
|
|
|
- |
|
|
|
(4,000 |
) |
Repayment
of debt
|
|
|
(3,333 |
) |
|
|
(104,037 |
) |
Repurchase
of common stock
|
|
|
(5 |
) |
|
|
(247 |
) |
Issuance
of common stock
|
|
|
4,663 |
|
|
|
2,509 |
|
Issuance
of common units of ONEOK Partners, net of discounts
|
|
|
322,721 |
|
|
|
- |
|
Dividends
paid
|
|
|
(46,701 |
) |
|
|
(42,080 |
) |
Distributions
to noncontrolling interests
|
|
|
(59,782 |
) |
|
|
(52,751 |
) |
Cash
used in financing activities
|
|
|
(354,307 |
) |
|
|
(985,581 |
) |
Change
in cash and cash equivalents
|
|
|
138,034 |
|
|
|
(433,305 |
) |
Cash
and cash equivalents at beginning of period
|
|
|
29,399 |
|
|
|
510,058 |
|
Cash
and cash equivalents at end of period
|
|
$ |
167,433 |
|
|
$ |
76,753 |
|
See
accompanying Notes to Consolidated Financial Statements.
|
|
ONEOK,
Inc. and Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF SHAREHOLDERS' 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
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
13,049 |
|
Repurchase
of common stock
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Common
stock issued
|
|
|
151,070 |
|
|
|
1 |
|
|
|
(7,480 |
) |
|
|
- |
|
Common
stock dividends -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$0.44
per share
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Issuance
of common units of ONEOK Partners
|
|
|
- |
|
|
|
- |
|
|
|
50,731 |
|
|
|
- |
|
Distributions
to noncontrolling interests
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
March
31, 2010
|
|
|
122,545,085 |
|
|
$ |
1,225 |
|
|
$ |
1,365,591 |
|
|
$ |
(105,564 |
) |
See
accompanying Notes to Consolidated Financial Statements.
|
|
|
|
|
|
|
|
|
ONEOK,
Inc. and Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
|
|
|
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ONEOK
Shareholders' Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncontrolling
|
|
|
|
|
|
|
|
|
|
|
|
|
Interests
in
|
|
|
Total
|
|
|
|
Retained
|
|
|
Treasury
|
|
|
Consolidated
|
|
|
Shareholders'
|
|
(Unaudited)
|
|
Earnings
|
|
|
Stock
|
|
|
Subsidiaries
|
|
|
Equity
|
|
|
(Thousands
of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2009
|
|
$ |
1,685,710 |
|
|
$ |
(683,467 |
) |
|
$ |
1,238,268 |
|
|
$ |
3,445,462 |
|
Net
income
|
|
|
154,539 |
|
|
|
- |
|
|
|
32,181 |
|
|
|
186,720 |
|
Other
comprehensive income
|
|
|
- |
|
|
|
- |
|
|
|
16,287 |
|
|
|
29,336 |
|
Repurchase
of common stock
|
|
|
- |
|
|
|
(5 |
) |
|
|
- |
|
|
|
(5 |
) |
Common
stock issued
|
|
|
- |
|
|
|
9,369 |
|
|
|
- |
|
|
|
1,890 |
|
Common
stock dividends -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$0.44
per share
|
|
|
(46,701 |
) |
|
|
- |
|
|
|
- |
|
|
|
(46,701 |
) |
Issuance
of common units of ONEOK Partners
|
|
|
- |
|
|
|
- |
|
|
|
271,990 |
|
|
|
322,721 |
|
Distributions
to noncontrolling interests
|
|
|
- |
|
|
|
- |
|
|
|
(59,782 |
) |
|
|
(59,782 |
) |
March
31, 2010
|
|
$ |
1,793,548 |
|
|
$ |
(674,103 |
) |
|
$ |
1,498,944 |
|
|
$ |
3,879,641 |
|
ONEOK,
Inc. and Subsidiaries
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
(Unaudited)
|
|
2010
|
|
|
2009
|
|
|
|
(Thousands
of dollars)
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
186,720 |
|
|
$ |
163,549 |
|
Other
comprehensive income (loss), net of tax
|
|
|
|
|
|
|
|
|
Unrealized
gains on energy marketing and risk management
|
|
|
|
|
|
|
|
|
assets/liabilities,
net of tax of $(18,839) and $(38,232), respectively
|
|
|
43,489 |
|
|
|
60,497 |
|
Realized
gains in net income, net of tax of $8,022 and
|
|
|
|
|
|
|
|
|
$27,678,
respectively
|
|
|
(10,058 |
) |
|
|
(53,919 |
) |
Unrealized
holding gains (losses) on available-for-sale securities,
|
|
|
|
|
|
|
|
|
net
of tax of $62 and $(118), respectively
|
|
|
(97 |
) |
|
|
188 |
|
Change
in pension and postretirement benefit plan liability, net of
tax
|
|
|
|
|
|
|
|
|
of
$2,533 and $1,599, respectively
|
|
|
(4,016 |
) |
|
|
(2,534 |
) |
Other,
net of tax of $(11) and $(51), respectively
|
|
|
18 |
|
|
|
190 |
|
Total
other comprehensive income, net of tax
|
|
|
29,336 |
|
|
|
4,422 |
|
Comprehensive
income
|
|
|
216,056 |
|
|
|
167,971 |
|
Less:
Comprehensive income attributable to noncontrolling
interests
|
|
|
48,468 |
|
|
|
31,222 |
|
Comprehensive
income attributable to ONEOK
|
|
$ |
167,588 |
|
|
$ |
136,749 |
|
See
accompanying Notes to Consolidated Financial Statements.
|
|
|
|
|
|
|
|
|
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 months ended March 31, 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 Updates
The
following recently issued accounting standards updates affect 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 this
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.
Embedded Credit Derivatives -
In March 2010, the FASB issued ASU 2010-11, “Scope Exception Related to Embedded
Credit Derivatives,” which clarified that disclosures required for credit
derivatives do not apply to an embedded derivative’s feature related to the
transfer of credit risk that is only in the form of subordination of one
financial instrument to another. This guidance will be effective for our
September 30, 2010, Quarterly Report and will be applied prospectively. We
are currently reviewing the applicability of ASU 2010-11 to our consolidated
financial statement and related disclosures.
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 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:
|
|
March
31, 2010
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Netting
|
|
|
Total
|
|
|
|
(Thousands
of dollars)
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exchange-traded
contracts
|
|
$ |
134,991 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
134,991 |
|
Over-the-counter
financial contracts
|
|
|
- |
|
|
|
62,962 |
|
|
|
518,619 |
|
|
|
- |
|
|
|
581,581 |
|
Physical
contracts
|
|
|
- |
|
|
|
12,734 |
|
|
|
52,007 |
|
|
|
- |
|
|
|
64,741 |
|
Foreign
Exchange Contracts
|
|
|
73 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
73 |
|
Netting
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(602,753 |
) |
|
|
(602,753 |
) |
Total
derivatives
|
|
|
135,064 |
|
|
|
75,696 |
|
|
|
570,626 |
|
|
|
(602,753 |
) |
|
|
178,633 |
|
Trading
securities (b)
|
|
|
7,458 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
7,458 |
|
Available-for-sale
investment securities (c)
|
|
|
2,529 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,529 |
|
Total
assets
|
|
$ |
145,051 |
|
|
$ |
75,696 |
|
|
$ |
570,626 |
|
|
$ |
(602,753 |
) |
|
$ |
188,620 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exchange-traded
contracts
|
|
$ |
(140,926 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(140,926 |
) |
Over-the-counter
financial contracts
|
|
|
- |
|
|
|
(56,685 |
) |
|
|
(401,329 |
) |
|
|
- |
|
|
|
(458,014 |
) |
Physical
contracts
|
|
|
- |
|
|
|
(4,423 |
) |
|
|
(21,724 |
) |
|
|
- |
|
|
|
(26,147 |
) |
Netting
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
536,853 |
|
|
|
536,853 |
|
Total
derivatives
|
|
|
(140,926 |
) |
|
|
(61,108 |
) |
|
|
(423,053 |
) |
|
|
536,853 |
|
|
|
(88,234 |
) |
Fair
value of firm commitments (d)
|
|
|
- |
|
|
|
- |
|
|
|
(111,597 |
) |
|
|
- |
|
|
|
(111,597 |
) |
Total
liabilities
|
|
$ |
(140,926 |
) |
|
$ |
(61,108 |
) |
|
$ |
(534,650 |
) |
|
$ |
536,853 |
|
|
$ |
(199,831 |
) |
(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 March 31, 2010, we held $70.5 million of cash collateral and
had posted $4.6 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.
|
|
|
|
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
three months ended March 31, 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 and physical forward contracts,
NGL swaps and interest-rate swaps. Also included in Level 3 are the
fair values of firm commitments and long-term debt that have been
hedged. 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.
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)
|
|
January
1, 2010
|
|
$ |
136,694 |
|
|
$ |
(134,620 |
) |
|
$ |
2,074 |
|
Total
realized/unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
Included
in earnings (a)
|
|
|
(4,496 |
) |
|
|
23,023 |
|
|
|
18,527 |
|
Included
in other comprehensive income (loss)
|
|
|
13,222 |
|
|
|
- |
|
|
|
13,222 |
|
Transfers
into Level 3
|
|
|
1,468 |
|
|
|
- |
|
|
|
1,468 |
|
Transfers
out of Level 3
|
|
|
685 |
|
|
|
- |
|
|
|
685 |
|
March
31, 2010
|
|
$ |
147,573 |
|
|
$ |
(111,597 |
) |
|
$ |
35,976 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 March 31, 2010 (a)
|
|
$ |
18,458 |
|
|
$ |
(7,046 |
) |
|
$ |
11,412 |
|
(a)
- Reported in revenues and cost of sales and fuel in our Consolidated
Statements of Income.
|
|
|
|
|
|
|
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
|
|
110,002 |
|
(a)
|
|
|
(153,391 |
) |
(a)
|
|
|
1,455 |
|
(b)
|
|
|
(41,934 |
) |
Included
in other comprehensive income (loss)
|
|
(7,730 |
) |
|
|
|
- |
|
|
|
|
- |
|
|
|
|
(7,730 |
) |
Maturities
|
|
- |
|
|
|
|
- |
|
|
|
|
100,000 |
|
|
|
|
100,000 |
|
Terminations
prior to maturity
|
|
- |
|
|
|
|
- |
|
|
|
|
70,000 |
|
|
|
|
70,000 |
|
Transfers
in and/or out of Level 3
|
|
25,611 |
|
|
|
|
- |
|
|
|
|
- |
|
|
|
|
25,611 |
|
March
31, 2009
|
$ |
170,238 |
|
|
|
$ |
(111,212 |
) |
|
|
$ |
- |
|
|
|
$ |
59,026 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 March 31, 2009 (a)
|
$ |
136,563 |
|
|
|
$ |
(138,637 |
) |
|
|
$ |
- |
|
|
|
$ |
(2,074 |
) |
(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 $4.9
billion at March 31, 2010, and $4.8 billion at December 31, 2009. The
book value of long-term debt, including current maturities, was $4.6 billion at
March 31, 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.
|
The
following derivative instruments are used to manage our exposure to these
risks:
·
|
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.
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.
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:
|
|
March
31, 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
Services - fair value hedges
|
|
$ |
156,762 |
|
|
|
$ |
(45,178 |
) |
|
|
$ |
197,037 |
|
|
|
$ |
(59,731 |
) |
Energy
Services - cash flow hedges
|
|
|
68,437 |
|
(b)
|
|
|
(40,377 |
) |
|
|
|
115,215 |
|
(c)
|
|
|
(53,265 |
) |
ONEOK
Partners - cash flow hedges
|
|
|
21,483 |
|
|
|
|
(10,198 |
) |
|
|
|
459 |
|
|
|
|
(18,772 |
) |
Total
derivatives designated as hedging instruments
|
|
|
246,682 |
|
|
|
|
(95,753 |
) |
|
|
|
312,711 |
|
|
|
|
(131,768 |
) |
Derivatives
not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-trading
instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exchange-traded
contracts
|
|
|
2,586 |
|
|
|
|
(24,183 |
) |
|
|
|
24,692 |
|
|
|
|
(20,657 |
) |
Over-the-counter
financial contracts
|
|
|
368,439 |
|
|
|
|
(382,695 |
) |
|
|
|
382,783 |
|
|
|
|
(427,057 |
) |
Physical
contracts
|
|
|
63,713 |
|
|
|
|
(25,868 |
) |
|
|
|
46,598 |
|
|
|
|
(16,234 |
) |
Trading
instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exchange-traded
contracts
|
|
|
26,953 |
|
|
|
|
(16,447 |
) |
|
|
|
15,151 |
|
|
|
|
(16,153 |
) |
Over-the-counter
financial contracts
|
|
|
72,940 |
|
|
|
|
(80,141 |
) |
|
|
|
44,600 |
|
|
|
|
(42,181 |
) |
Total
commodity contracts
|
|
|
534,631 |
|
|
|
|
(529,334 |
) |
|
|
|
513,824 |
|
|
|
|
(522,282 |
) |
Energy
Services - foreign exchange contracts
|
|
|
73 |
|
|
|
|
- |
|
|
|
|
28 |
|
|
|
|
(81 |
) |
Total
derivatives not designated as hedging instruments
|
|
|
534,704 |
|
|
|
|
(529,334 |
) |
|
|
|
513,852 |
|
|
|
|
(522,363 |
) |
Total
derivatives
|
|
$ |
781,386 |
|
|
|
$ |
(625,087 |
) |
|
|
$ |
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.
|
|
Notional
Quantities for Derivative Instruments
The
following table sets forth the notional quantities for derivative instruments
held for the periods indicated:
|
|
|
March
31, 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
|
|
|
2.8 |
|
|
|
(9.6 |
) |
|
|
6.4 |
|
|
|
(20.7 |
) |
|
Swaps
|
|
|
14.5 |
|
|
|
(49.5 |
) |
|
|
18.1 |
|
|
|
(80.7 |
) |
-
Crude oil and NGLs
(MMBbl)
|
Swaps
|
|
|
- |
|
|
|
(2.4 |
) |
|
|
- |
|
|
|
(2.4 |
) |
Basis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
Natural gas (Bcf)
|
Forwards
and swaps
|
|
|
16.3 |
|
|
|
(55.3 |
) |
|
|
23.7 |
|
|
|
(99.6 |
) |
Fair
value hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
Natural gas (Bcf)
|
Forwards
and swaps
|
|
|
166.8 |
|
|
|
(166.8 |
) |
|
|
210.4 |
|
|
|
(210.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed
price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
Natural gas (Bcf)
|
Exchange
futures
|
|
|
27.3 |
|
|
|
(20.9 |
) |
|
|
38.8 |
|
|
|
(22.7 |
) |
|
Forwards
and swaps
|
|
|
96.0 |
|
|
|
(106.9 |
) |
|
|
100.6 |
|
|
|
(117.4 |
) |
|
Options
|
|
|
67.5 |
|
|
|
(44.2 |
) |
|
|
102.6 |
|
|
|
(80.6 |
) |
-
Foreign currency
(Millions of dollars)
|
Swaps
|
|
$ |
2.6 |
|
|
$ |
- |
|
|
$ |
4.6 |
|
|
$ |
- |
|
Basis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
Natural gas (Bcf)
|
Forwards
and swaps
|
|
|
868.8 |
|
|
|
(869.8 |
) |
|
|
940.7 |
|
|
|
(947.1 |
) |
Index
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
Natural gas
(Bcf)
|
Forwards
and swaps
|
|
|
63.7 |
|
|
|
(13.6 |
) |
|
|
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 March 31, 2010,
includes gains of approximately $13.2 million, net of tax, related to these
hedges that will be realized within the next 21 months as the forecasted
transactions affect earnings. If prices remain at current levels, we
will recognize $11.6 million in net gains over the next 12 months, and we will
recognize net gains of $1.6 million thereafter.
For the
three months ended March 31, 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
|
|
Derivatives
in Cash Flow
Hedging
Relationships
|
March
31,
|
2010
|
|
2009
|
|
(Thousands
of dollars)
|
Commodity
contracts
|
$ |
62,328 |
|
$ |
98,608 |
|
Interest
rate contracts
|
|
- |
|
|
121 |
|
Total
gain recognized in other comprehensive
income
(loss) on derivatives (effective portion)
|
$ |
62,328 |
|
$ |
98,729 |
|
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
|
|
Three
Months Ended
|
|
Derivatives
in Cash Flow
Hedging
Relationships
|
Accumulated
Other Comprehensive Income
|
|
March
31,
|
|
(Loss)
into Net Income (Effective Portion)
|
|
2010
|
|
2009
|
|
|
|
(Thousands
of dollars)
|
Commodity
contracts
|
Revenues
|
|
$ |
29,956 |
|
|
$ |
82,715 |
|
Commodity
contracts
|
Cost
of sales and fuel
|
|
|
(12,097 |
) |
|
|
(1,554 |
) |
Interest
rate contracts
|
Interest
expense
|
|
|
221 |
|
|
|
436 |
|
Total
gain (loss) reclassified from accumulated other comprehensive
income
(loss) into net income on derivatives (effective portion)
|
|
$ |
18,080 |
|
|
$ |
81,597 |
|
|
Location
of Gain (Loss) Recognized in Income on
|
|
Three
Months Ended
|
|
Derivatives
in Cash Flow
Hedging
Relationships
|
Derivatives
(Ineffective Portion and Amount
|
|
March
31,
|
Excluded
from Effectiveness Testing)
|
|
2010
|
|
2009
|
|
|
|
(Thousands
of dollars)
|
Commodity
contracts
|
Revenues
|
|
$ |
1,016 |
|
|
$ |
3,048 |
|
Commodity
contracts
|
Cost
of sales and fuel
|
|
|
(877 |
) |
|
|
(530 |
) |
Total
gain (loss) recognized in income on derivatives (ineffective
portion
and amount excluded from effectiveness testing)
|
|
$ |
139 |
|
|
$ |
2,518 |
|
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 three months ended March 31, 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.
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
|
|
Derivatives
Not Designated as
Hedging
Instruments
|
Location
of Gain
|
March
31,
|
|
2010
|
2009
|
|
|
|
(Thousands
of dollars)
|
|
Commodity
contracts - trading
|
Revenues
|
$ |
2,028 |
|
$ |
3,305 |
|
Commodity
contracts - non-trading (a)
|
Cost
of gas and fuel
|
|
(41 |
) |
|
(539 |
) |
Foreign
exchange contracts
|
Revenues
|
|
59 |
|
|
(262 |
) |
Total
gain recognized in income on derivatives
|
|
$ |
2,046 |
|
$ |
2,504 |
|
(a)
- For the three months ended March 31, 2010 and 2009, we recognized $3.9
million and $2.1 million, respectively, 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.
|
|
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 March 31, 2010 and 2009, were $2.5 million and
$2.6 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
|
|
$ |
4.8 |
|
$ |
2.8 |
|
$ |
7.6 |
|
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 March 31,
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 included gains of $1.3 million and
losses of $0.8 million for the three months ended March 31, 2010 and 2009,
respectively.
For the
three months ended March 31, 2010, cost of sales and fuel in our Consolidated
Statements of Income includes gains of $10.8 million related to the change in
fair value of derivatives declared as fair value hedges. Revenues
include losses of $9.6 million for the three months ended March 31, 2010, to
recognize the change in fair value of the hedged firm commitments.
Credit Risk - We monitor the
creditworthiness of our counterparties and compliance with management’s risk
tolerance as determined 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 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 March 31, 2010, was
$14.0 million for which we have posted collateral of $4.6 million in the normal
course of business. If the contingent features underlying these
agreements were triggered on March 31, 2010, we would have been required to post
an additional $9.4 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 period indicated:
|
|
March
31, 2010
|
|
December
31, 2009
|
|
|
|
Investment
|
|
Non-investment
|
|
Not
|
|
|
|
Investment
|
|
Non-investment
|
|
Not
|
|
|
|
|
|
Grade
|
|
Grade
|
|
Rated
|
|
Total
|
|
Grade
|
|
Grade
|
|
Rated
|
|
Total
|
|
Counterparty
sector
|
|
(Thousands
of dollars)
|
|
Gas
and electric utilities
|
|
$ |
49,961 |
|
$ |
2,803 |
|
$ |
3,142 |
|
$ |
55,906 |
|
$ |
26,964 |
|
$ |
2,668 |
|
$ |
7,972 |
|
$ |
37,604 |
|
Oil
and gas
|
|
|
62,115 |
|
|
- |
|
|
1,825 |
|
|
63,940 |
|
|
54,578 |
|
|
224 |
|
|
10,084 |
|
|
64,886 |
|
Industrial
|
|
|
2 |
|
|
- |
|
|
7,210 |
|
|
7,212 |
|
|
689 |
|
|
- |
|
|
3 |
|
|
692 |
|
Financial
|
|
|
51,524 |
|
|
- |
|
|
15 |
|
|
51,539 |
|
|
32,880 |
|
|
- |
|
|
7 |
|
|
32,887 |
|
Other
|
|
|
- |
|
|
23 |
|
|
13 |
|
|
36 |
|
|
- |
|
|
55 |
|
|
40 |
|
|
95 |
|
Total
|
|
$ |
163,602 |
|
$ |
2,826 |
|
$ |
12,205 |
|
$ |
178,633 |
|
$ |
115,111 |
|
$ |
2,947 |
|
$ |
18,106 |
|
$ |
136,164 |
|
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
|
|
|
17,162
|
|
(97)
|
|
|
(4,016)
|
|
13,049
|
March
31, 2010
|
|
$ |
11,011
|
|
$1,344
|
|
$ |
(117,919)
|
|
$(105,564)
|
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 March 31, 2010, ONEOK’s stand-alone debt-to-capital
ratio, as defined by the ONEOK Credit Agreement, was 38.5 percent, and ONEOK was
in compliance with all covenants under the ONEOK Credit Agreement.
At March
31, 2010, ONEOK had no commercial paper outstanding and $37.0 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,
leaving $804.1 million of credit available under the ONEOK Credit
Agreement.
ONEOK had
no outstanding short-term debt at March 31, 2010. The average
interest rate on ONEOK’s commercial paper outstanding at December 31, 2009, was
0.30 percent.
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 March 31, 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.
At March
31, 2010, and December 31, 2009, ONEOK Partners had $310 million and $523
million, respectively, in borrowings outstanding under the ONEOK Partners Credit
Agreement and under the most restrictive provisions of the ONEOK Partners Credit
Agreement had $558 million and $367 million, respectively, of credit
available. At March 31, 2010,
and
December 31, 2009, ONEOK Partners had a total of $24.2 million issued in letters
of credit outside of the ONEOK Partners Credit Agreement.
The
average interest rate of short-term debt outstanding under the ONEOK Partners
Credit Agreement was 0.54 percent at March 31, 2010, and December 31,
2009.
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.
F. SHAREHOLDERS’
EQUITY
The
following table sets forth the changes in shareholders’ 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
|
|
|
|
March
31, 2010
|
|
|
March
31, 2009
|
|
|
|
ONEOK
Shareholders' Equity
|
|
Noncontrolling
Interests in Consolidated Subsidiaries
|
|
Total
Shareholders' Equity
|
|
|
ONEOK
Shareholders' Equity
|
|
Noncontrolling
Interests in Consolidated Subsidiaries
|
|
Total
Shareholders' 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
|
|
|
154,539 |
|
|
32,181 |
|
|
186,720 |
|
|
|
122,285 |
|
|
41,264 |
|
|
163,549 |
|
Other
comprehensive income (loss)
|
|
|
13,049 |
|
|
16,287 |
|
|
29,336 |
|
|
|
14,464 |
|
|
(10,042 |
) |
|
4,422 |
|
Repurchase
of common stock
|
|
|
(5 |
) |
|
- |
|
|
(5 |
) |
|
|
(247 |
) |
|
- |
|
|
(247 |
) |
Common
stock issued
|
|
|
1,890 |
|
|
- |
|
|
1,890 |
|
|
|
701 |
|
|
- |
|
|
701 |
|
Common
stock dividends
|
|
|
(46,701 |
) |
|
- |
|
|
(46,701 |
) |
|
|
(42,080 |
) |
|
- |
|
|
(42,080 |
) |
Issuance
of common units of ONEOK Partners
|
|
|
50,731 |
|
|
271,990 |
|
|
322,721 |
|
|
|
- |
|
|
- |
|
|
- |
|
Distributions
to noncontrolling interests
|
|
|
- |
|
|
(59,782 |
) |
|
(59,782 |
) |
|
|
- |
|
|
(52,751 |
) |
|
(52,751 |
) |
Ending
balance
|
|
$ |
2,380,697 |
|
$ |
1,498,944 |
|
$ |
3,879,641 |
|
|
$ |
2,183,293 |
|
$ |
1,057,840 |
|
$ |
3,241,133 |
|
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,
respectively, were $0.44 per share.
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
|
|
Postretirement
Benefits
|
|
|
Three
Months Ended
|
|
Three
Months Ended
|
|
|
March
31,
|
|
March
31,
|
|
|
2010
|
|
2009
|
|
2010
|
|
|
2009
|
|
|
(Thousands
of dollars)
|
|
Components
of net periodic benefit cost
|
|
|
|
|
|
|
|
|
|
Service
cost
|
$ |
4,819 |
|
$ |
4,984 |
|
$ |
1,231 |
|
|
$ |
1,293 |
|
Interest
cost
|
|
14,536 |
|
|
15,205 |
|
|
3,911 |
|
|
|
4,230 |
|
Expected
return on assets
|
|
(18,413 |
) |
|
(16,508 |
) |
|
(1,974 |
) |
|
|
(1,702 |
) |
Amortization
of unrecognized net asset at adoption
|
|
- |
|
|
- |
|
|
797 |
|
|
|
797 |
|
Amortization
of unrecognized prior service cost
|
|
320 |
|
|
391 |
|
|
(501 |
) |
|
|
(501 |
) |
Amortization
of net loss
|
|
6,889 |
|
|
6,814 |
|
|
1,752 |
|
|
|
2,415 |
|
Net
periodic benefit cost
|
$ |
8,151 |
|
$ |
10,886 |
|
$ |
5,216 |
|
|
$ |
6,532 |
|
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 three months ended March 31, 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.
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 two locations, and we have completed or are near completion
of soil remediation at nine 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
months ended March 31, 2010 or 2009.
The EPA
is proposing to finalize the “Tailoring Rule” that will regulate greenhouse gas
emissions at certain facilities that emit more than 25,000 tons of greenhouse
gas emissions per year. Under the Prevention of Significant
Deterioration requirement for existing facilities, upon making a major
modification to a facility, the facility would be required to obtain permits
that demonstrate it has installed the best available technology to control
greenhouse gas emissions. The rule is expected to be phased in
beginning January 2011 and could impact some of our facilities. At
this time, potential costs, fees or expenses associated with the proposed
“Tailoring Rule” are unknown.
In
addition, the EPA has issued a proposed 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 proposed 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 liquidity.
Overland Pass Pipeline Company
- Overland Pass Pipeline Company is a joint venture between ONEOK Partners and a
subsidiary of The Williams Companies, Inc. (Williams). A subsidiary
of ONEOK Partners owns 99 percent of the joint venture and operates the
pipeline. On or before November 17, 2010, Williams has the option to
increase its ownership in Overland Pass Pipeline Company up to a total of 50
percent, with the purchase price being determined in accordance with the joint
venture’s operating agreement. If Williams exercises its option to
increase its ownership to 50 percent, Williams would have the option to become
operator. Should Williams exercise its option to obtain a 50 percent
ownership interest, ONEOK Partners may be required to deconsolidate Overland
Pass Pipeline Company and account for it under the equity method of
accounting.
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 primarily comprised 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
months ended March 31, 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:
Three
Months Ended
March
31, 2010
|
|
ONEOK
Partners
(a)
|
|
|
Distribution
(b)
|
|
|
Energy
Services
|
|
|
Other
and Eliminations
|
|
|
Total
|
|
|
|
(Thousands
of dollars)
|
Sales
to unaffiliated customers
|
|
$ |
2,067,075 |
|
|
$ |
997,908 |
|
|
$ |
858,232 |
|
|
$ |
752 |
|
|
$ |
3,923,967 |
|
Intersegment
revenues
|
|
|
136,931 |
|
|
|
3,491 |
|
|
|
335,602 |
|
|
|
(476,024 |
) |
|
|
- |
|
Total
revenues
|
|
$ |
2,204,006 |
|
|
$ |
1,001,399 |
|
|
$ |
1,193,834 |
|
|
$ |
(475,272 |
) |
|
$ |
3,923,967 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
margin
|
|
$ |
261,125 |
|
|
$ |
246,826 |
|
|
$ |
110,618 |
|
|
$ |
750 |
|
|
$ |
619,319 |
|
Operating
costs
|
|
|
96,306 |
|
|
|
99,776 |
|
|
|
7,426 |
|
|
|
(163 |
) |
|
|
203,345 |
|
Depreciation
and amortization
|
|
|
43,871 |
|
|
|
33,345 |
|
|
|
153 |
|
|
|
487 |
|
|
|
77,856 |
|
Loss
on sale of assets
|
|
|
(786 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(786 |
) |
Operating
income
|
|
$ |
120,162 |
|
|
$ |
113,705 |
|
|
$ |
103,039 |
|
|
$ |
426 |
|
|
$ |
337,332 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
earnings from investments
|
|
$ |
21,116 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
21,116 |
|
Investments
in unconsolidated
affiliates
|
|
$ |
762,435 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
762,435 |
|
Total
assets
|
|
$ |
7,697,369 |
|
|
$ |
3,092,696 |
|
|
$ |
666,812 |
|
|
$ |
872,315 |
|
|
$ |
12,329,192 |
|
Noncontrolling
interests in
consolidated
subsidiaries
|
|
$ |
5,387 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
1,493,557 |
|
|
$ |
1,498,944 |
|
Capital
expenditures
|
|
$ |
35,827 |
|
|
$ |
31,378 |
|
|
$ |
52 |
|
|
$ |
1,016 |
|
|
$ |
68,273 |
|
(a)
- Our ONEOK Partners segment has regulated and non-regulated
operations. Our ONEOK Partners segment’s regulated operations had
revenues of $152.1 million, net margin of $125.6 million and operating
income of $69.4 million.
|
(b)
- Our Distribution segment has regulated and non-regulated
operations. Our Distribution segment's regulated operations had
revenues of $857.6 million, net margin of $242.6 million and operating
income of 111.3 million.
|
Three
Months Ended
March
31, 2009
|
|
ONEOK
Partners
(a)
|
|
|
Distribution
(b)
|
|
|
Energy
Services
|
|
|
Other
and Eliminations
|
|
|
Total
|
|
|
|
(Thousands
of dollars)
|
|
Sales
to unaffiliated customers
|
|
$ |
1,106,730 |
|
|
$ |
849,354 |
|
|
$ |
832,984 |
|
|
$ |
759 |
|
|
$ |
2,789,827 |
|
Intersegment
revenues
|
|
|
144,135 |
|
|
|
2,310 |
|
|
|
289,085 |
|
|
|
(435,530 |
) |
|
|
- |
|
Total
revenues
|
|
$ |
1,250,865 |
|
|
$ |
851,664 |
|
|
$ |
1,122,069 |
|
|
$ |
(434,771 |
) |
|
$ |
2,789,827 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
margin
|
|
$ |
253,541 |
|
|
$ |
238,953 |
|
|
$ |
58,174 |
|
|
$ |
743 |
|
|
$ |
551,411 |
|
Operating
costs
|
|
|
89,446 |
|
|
|
91,438 |
|
|
|
6,146 |
|
|
|
(84 |
) |
|
|
186,946 |
|
Depreciation
and amortization
|
|
|
39,940 |
|
|
|
31,626 |
|
|
|
131 |
|
|
|
429 |
|
|
|
72,126 |
|
Gain
on sale of assets
|
|
|
664 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
664 |
|
Operating
income
|
|
$ |
124,819 |
|
|
$ |
115,889 |
|
|
$ |
51,897 |
|
|
$ |
398 |
|
|
$ |
293,003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
earnings from investments
|
|
$ |
21,222 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
21,222 |
|
Capital
expenditures
|
|
$ |
192,494 |
|
|
$ |
44,652 |
|
|
$ |
- |
|
|
$ |
5,881 |
|
|
$ |
243,027 |
|
(a)
- Our ONEOK Partners segment has regulated and non-regulated
operations. Our ONEOK Partners segment’s regulated operations had
revenues of $119.5 million, net margin of $95.5 million and operating
income of $45.3 million.
|
|
(b)
- Our Distribution segment has regulated and non-regulated
operations. Our Distribution segment's regulated operations had
revenues of $754.4 million, net margin of $234.6 million and operating
income of $112.9 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
|
|
|
|
March
31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Thousands
of dollars)
|
|
Northern
Border Pipeline
|
|
$ |
14,846 |
|
|
$ |
16,038 |
|
Bighorn
Gas Gathering, L.L.C.
|
|
|
237 |
|
|
|
2,086 |
|
Fort
Union Gas Gathering, L.L.C.
|
|
|
3,558 |
|
|
|
2,210 |
|
Lost
Creek Gathering Company, L.L.C.
|
|
|
1,402 |
|
|
|
890 |
|
Other
|
|
|
1,073 |
|
|
|
(2 |
) |
Equity
earnings from investments
|
|
$ |
21,116 |
|
|
$ |
21,222 |
|
Unconsolidated Affiliates Financial
Information - The following table sets forth summarized combined
financial information of our unconsolidated affiliates for the periods
indicated:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Thousands
of dollars)
|
|
Income
Statement
|
|
|
|
|
|
|
Operating
revenues
|
|
$ |
99,231 |
|
|
$ |
106,066 |
|
Operating
expenses
|
|
$ |
44,715 |
|
|
$ |
44,803 |
|
Net
income
|
|
$ |
46,911 |
|
|
$ |
50,516 |
|
|
|
|
|
|
|
|
|
|
Distributions
paid to us
|
|
$ |
23,529 |
|
|
$ |
33,331 |
|
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
include a $1.5 million and $8.1 million return of investment for the three
months ended March 31, 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 March 31, 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
|
|
$ |
154,539 |
|
|
106,132 |
|
$ |
1.46 |
|
Diluted
EPS from continuing operations
|
|
|
|
|
|
|
|
|
|
|
Effect
of options and other dilutive securities
|
|
|
- |
|
|
1,278 |
|
|
|
|
Net
income attributable to ONEOK available for common stock
|
|
|
|
|
|
|
|
|
|
|
and
common stock equivalents
|
|
$ |
154,539 |
|
|
107,410 |
|
$ |
1.44 |
|
|
Three
Months Ended March 31, 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
|
|
$ |
122,285 |
|
|
|
105,162 |
|
|
$ |
1.16 |
|
Diluted
EPS from continuing operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect
of options and other dilutive securities
|
|
|
- |
|
|
|
571 |
|
|
|
|
|
Net
income attributable to ONEOK available for common stock
|
|
|
|
|
|
|
|
|
|
|
|
|
and
common stock equivalents
|
|
$ |
122,285 |
|
|
|
105,733 |
|
|
$ |
1.16 |
|
There
were no option shares excluded from the calculation of diluted EPS for the three
months ended March 31, 2010, and 265,043 option shares excluded from the
calculation of diluted EPS for the three months ended March 31,
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.
|
March
31,
|
|
|
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 three months ended March 31,
2010.
Cash Distributions - The
following table sets forth ONEOK Partners’ general partner and incentive
distributions declared for the periods indicated:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2010
|
|
|
2009
|
|
|
(Thousands
of dollars)
|
|
General
partner distributions
|
|
$ |
2,833 |
|
|
$ |
2,419 |
|
Incentive
distributions
|
|
|
25,710 |
|
|
|
20,320 |
|
Total
distributions to general partner
|
|
$ |
28,543 |
|
|
$ |
22,739 |
|
The
quarterly distribution paid by ONEOK Partners to limited partners in the first
quarter of 2010 was $1.10 per unit. The quarterly distribution paid
by ONEOK Partners to limited partners in the first quarter of 2009 was $1.08 per
unit.
For the
three months ended March 31, 2010 and 2009, cash distributions paid by ONEOK
Partners to us totaled $72.7 million and $68.5 million,
respectively.
In April
2010, a cash distribution from ONEOK Partners of $1.11 per unit payable in the
second quarter was declared. On May 14, 2010, we will receive the
related incentive distribution of $25.7 million for the first 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 utilize ONEOK Partners’ 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 a portion of 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
include 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 for the periods
indicated:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Thousands
of dollars)
|
|
Revenues
|
|
$ |
136,931 |
|
|
$ |
144,135 |
|
|
|
|
|
|
|
|
|
|
Expenses
|
|
|
|
|
|
|
|
|
Cost
of sales and fuel
|
|
$ |
17,759 |
|
|
$ |
16,638 |
|
Administrative
and general expenses
|
|
|
51,025 |
|
|
|
48,623 |
|
Total
expenses
|
|
$ |
68,784 |
|
|
$ |
65,261 |
|
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 months ended March 31, 2010, are not necessarily
indicative of the results that may be expected for a 12-month
period.
EXECUTIVE
SUMMARY
Outlook - We expect a moderate
economic recovery in 2010, with inflationary pressures beginning in
2011. Although recent 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 during 2010,
compared with 2009; however, inflation risks may increase the cost of
capital. 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 during 2010, compared with 2009.
Recent Developments - 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. These
investments include construction of 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.
ONEOK
Partners will invest an additional $55 million in the Woodford Shale in Oklahoma
for new well connections in 2010 and 2011 and to connect its existing gathering
system to its existing Maysville, Oklahoma, natural gas processing facility, as
well as the connection of a new plant to ONEOK Partners’ NGL gathering
system.
Operating Results - Diluted
earnings per share of common stock from continuing operations (EPS) were $1.44
and $1.16 for the three months ended March 31, 2010 and 2009,
respectively. Operating income for the three months ended March 31,
2010, increased to $337.3 million from $293.0 million for the same period last
year. This increase in operating income is due primarily to increased
net margins 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.
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.
Dividends/Distributions - We
declared a quarterly dividend of $0.44 per share ($1.76 per share on an
annualized basis) in April 2010, an increase of 10 percent from the $0.40 per
share declared in April 2009. ONEOK Partners declared a cash
distribution of $1.11 per unit ($4.44 per unit on an annualized basis) in April
2010, an increase of approximately 3 percent from the $1.08 per unit declared in
April 2009.
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.
REGULATORY
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.
The EPA
is proposing to finalize the “Tailoring Rule” that will regulate greenhouse gas
emissions at certain facilities that emit more than 25,000 tons of greenhouse
gas emissions per year. Under the Prevention of Significant
Deterioration requirement for existing facilities, upon making a major
modification to a facility, the facility would be required to obtain permits
that demonstrate it has installed the best available technology to control
greenhouse gas emissions. The rule is expected to be phased in
beginning January 2011 and could impact some of our facilities. At
this time, potential costs, fees or expenses associated with the proposed
“Tailoring Rule” are unknown.
In
addition, the EPA has issued a proposed 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 proposed 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 -
It is unclear how Congress and the current Administration’s efforts to
improve market transparency and stabilize the over-the-counter (OTC) derivative
markets will impact our ability to access OTC energy derivatives products and
markets, which are critical to our business. We use the OTC markets
to manage business risks including fluctuating commodity prices, interest rates,
currency rates and for the hedging of inventory and capacity
contracts. Most of the current proposals before Congress contain
exemptions for these activities that would limit the impact on our
operations. Additional matters associated with these proposals that
are not yet defined include the potential for increased capital requirements and
a reduction in the overall liquidity of the markets. There may also
be an administrative burden of new reporting and record keeping required by one
or more of the federal agencies providing market oversight.
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 39.
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:
·
|
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;
and
|
·
|
ASU
2010-11, “Scope Exception Related to Embedded Credit Derivatives,” which
will be effective for our September 30, 2010, Quarterly Report and will be
applied prospectively. We are currently reviewing the
applicability of ASU 2010-11 to our consolidated financial statements and
related disclosures.
|
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 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
|
|
|
Variances
|
|
|
|
March
31,
|
|
|
2010
vs. 2009
|
|
Financial
Results
|
|
2010
|
|
|
2009
|
|
|
Increase
(Decrease)
|
|
|
|
(Millions
of dollars)
|
|
Revenues
|
|
$ |
3,923.9 |
|
|
$ |
2,789.8 |
|
|
$ |
1,134.1 |
|
|
|
41 |
% |
Cost
of sales and fuel
|
|
|
3,304.6 |
|
|
|
2,238.4 |
|
|
|
1,066.2 |
|
|
|
48 |
% |
Net
margin
|
|
|
619.3 |
|
|
|
551.4 |
|
|
|
67.9 |
|
|
|
12 |
% |
Operating
costs
|
|
|
203.3 |
|
|
|
187.0 |
|
|
|
16.3 |
|
|
|
9 |
% |
Depreciation
and amortization
|
|
|
77.9 |
|
|
|
72.1 |
|
|
|
5.8 |
|
|
|
8 |
% |
Gain
(loss) on sale of assets
|
|
|
(0.8 |
) |
|
|
0.7 |
|
|
|
(1.5 |
) |
|
|
|
* |
Operating
income
|
|
$ |
337.3 |
|
|
$ |
293.0 |
|
|
$ |
44.3 |
|
|
|
15 |
% |
Equity
earnings from investments
|
|
$ |
21.1 |
|
|
$ |
21.2 |
|
|
$ |
(0.1 |
) |
|
|
(0 |
%) |
Allowance
for equity funds used
during
construction
|
|
$ |
0.2 |
|
|
$ |
9.0 |
|
|
$ |
(8.8 |
) |
|
|
(98 |
%) |
Interest
expense
|
|
$ |
(76.5 |
) |
|
$ |
(78.0 |
) |
|
$ |
(1.5 |
) |
|
|
(2 |
%) |
Net
income attributable to
noncontrolling
interests
|
|
$ |
(32.2 |
) |
|
$ |
(41.3 |
) |
|
$ |
(9.1 |
) |
|
|
(22 |
%) |
Capital
expenditures
|
|
$ |
68.3 |
|
|
$ |
243.0 |
|
|
$ |
(174.7 |
) |
|
|
(72 |
%) |
*
Percentage change is greater than 100 percent.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
markets were affected by increased commodity prices during the three months
ended March 31, 2010, compared with the same period last year. This
increase in commodity prices had a direct impact on our revenues and cost of
sales and fuel. Net margin increased for the three months ended March
31, 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 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 Distribution segment from increased revenue from various
riders and higher transportation and sales volumes;
and
|
·
|
increased
net margin in our ONEOK Partners segment, due primarily
to:
|
-
|
higher
NGL volumes gathered, fractionated and transported, associated with the
completion of the Arbuckle Pipeline, Piceance lateral and D-J Basin
lateral, as well as new NGL supply connections;
and
|
-
|
higher
natural gas transportation margins from the Guardian Pipeline expansion
and extension that was completed in February 2009 and an increase in
volumes contracted on Midwestern Gas Transmission; offset partially
by
|
-
|
lower
optimization margins due to less NGL fractionation and transportation
capacity available for optimization;
and
|
-
|
the
impact of operational measurement gains and losses as compared with the
same period last year.
|
Operating
costs increased for the three months ended March 31, 2010, compared with the
same period last year, due to the operation of the recently completed capital
projects and higher employee-related costs in our ONEOK Partners segment, and
the recognition of previously deferred costs and increased employee-related
costs in our Distribution segment.
Depreciation
and amortization expense increased for the three months ended March 31, 2010,
compared with the same period last year, primarily as a result
of ONEOK Partners’ completed capital projects.
Allowance
for equity funds used during construction decreased for the three months ended
March 31, 2010, compared with the same period last year, due to the completion
of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral.
Net
income attributable to noncontrolling interests for the three months ended March
31, 2010 and 2009, reflects the remaining 57.2 percent and 52.3 percent,
respectively, of ONEOK Partners that we do not own. The decrease in
net income attributable to noncontrolling interests is due to the decreased
income of our ONEOK Partners segment.
Capital
expenditures decreased for the three months ended March 31, 2010, compared with
the same period last year, due to the completion of the capital projects in our
ONEOK Partners segment.
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.
Our ONEOK
Partners segment is engaged in the gathering and processing of natural gas and
gathering, primarily in the Mid-Continent and Rocky Mountain regions, which
include the Anadarko Basin of Oklahoma, Hugoton and Central Kansas Uplift Basins
of Kansas; and the Williston Basin of Montana and North Dakota and the Powder
River Basin of Wyoming, respectively. These operations include the
gathering of natural gas produced from crude oil and natural gas
wells. 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 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.
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.
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
|
|
|
Variances
|
|
|
|
March
31,
|
|
|
2010
vs. 2009
|
|
Financial
Results
|
|
2010
|
|
|
2009
|
|
|
Increase
(Decrease)
|
|
|
|
(Millions
of dollars)
|
|
Revenues
|
|
$ |
2,204.0 |
|
|
$ |
1,250.9 |
|
|
$ |
953.1 |
|
|
|
76 |
% |
Cost
of sales and fuel
|
|
|
1,942.9 |
|
|
|
997.4 |
|
|
|
945.5 |
|
|
|
95 |
% |
Net
margin
|
|
|
261.1 |
|
|
|
253.5 |
|
|
|
7.6 |
|
|
|
3 |
% |
Operating
costs
|
|
|
96.2 |
|
|
|
89.5 |
|
|
|
6.7 |
|
|
|
7 |
% |
Depreciation
and amortization
|
|
|
43.9 |
|
|
|
39.9 |
|
|
|
4.0 |
|
|
|
10 |
% |
Gain
(loss) on sale of assets
|
|
|
(0.8 |
) |
|
|
0.7 |
|
|
|
(1.5 |
) |
|
|
|
* |
Operating
income
|
|
$ |
120.2 |
|
|
$ |
124.8 |
|
|
$ |
(4.6 |
) |
|
|
(4 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
earnings from investments
|
|
$ |
21.1 |
|
|
$ |
21.2 |
|
|
$ |
(0.1 |
) |
|
|
(0 |
%) |
Allowance
for equity funds used
during
construction
|
|
$ |
0.2 |
|
|
$ |
9.0 |
|
|
$ |
(8.8 |
) |
|
|
(98 |
%) |
Interest
expense
|
|
$ |
(54.2 |
) |
|
$ |
(50.9 |
) |
|
$ |
3.3 |
|
|
|
6 |
% |
Capital
expenditures
|
|
$ |
35.8 |
|
|
$ |
192.5 |
|
|
$ |
(156.7 |
) |
|
|
(81 |
%) |
*
Percentage change is greater than 100 percent.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
margin increased for the three months ended March 31, 2010, compared with the
same period last year, due to the following:
·
|
an
increase of $20.0 million due to higher NGL volumes gathered, fractionated
and transported, associated with the completion of the Arbuckle Pipeline,
Piceance lateral and D-J Basin lateral, as well as new NGL supply
connections; and
|
·
|
an
increase of $9.2 million from higher natural gas transportation margins
from the Guardian Pipeline expansion and extension that was completed in
February 2009 and an increase in volumes contracted on Midwestern Gas
Transmission; offset partially by
|
·
|
a
decrease of $14.8 million related to lower optimization margins due to
less NGL fractionation and transportation capacity available for
optimization;
|
·
|
a
decrease of $6.8 million due to the impact of operational measurement
gains and losses as compared with the same period last year;
and
|
·
|
a
decrease of $4.8 million due to lower natural gas volumes gathered,
primarily in the Powder River Basin, and a favorable contract settlement
recognized in the first quarter of
2009.
|
Operating
costs increased for the three months ended March 31, 2010, compared with the
same period last year, due to the operation of ONEOK Partners’ recently
completed capital projects and higher employee-related costs.
Depreciation
and amortization expense increased for the three months ended March 31, 2010,
compared with the same period last year, as a result of ONEOK Partners’
completed capital projects.
Allowance
for equity funds used during construction decreased for the three months ended
March 31, 2010, compared with the same period last year, due to the completion
of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral.
Capital
expenditures decreased for the three months ended March 31, 2010, compared with
the same period last year, due to the completions of ONEOK Partners’ capital
projects discussed in Part II, Item 7, Management’s Discussion and Analysis of
Financial Condition and Results of Operations of our Annual Report.
Selected Operating Information
- The following table sets forth selected operating information for our ONEOK
Partners segment for the periods indicated:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
Operating
Information
|
|
2010
|
|
|
2009
|
|
Natural
gas gathered (BBtu/d)
(a)
|
|
|
1,092 |
|
|
|
1,163 |
|
Natural
gas processed (BBtu/d)
(a)
|
|
|
664 |
|
|
|
653 |
|
Natural
gas transportation capacity contracted (MMcf/d)
|
|
|
5,860 |
|
|
|
5,247 |
|
Transportation
capacity subscribed
|
|
|
91 |
% |
|
|
79 |
% |
Residue
gas sales (BBtu/d)
(a)
|
|
|
275 |
|
|
|
285 |
|
NGL
sales (MBbl/d)
|
|
|
427 |
|
|
|
380 |
|
NGLs
fractionated (MBbl/d)
|
|
|
492 |
|
|
|
465 |
|
NGLs
transported-gathering lines (MBbl/d)
|
|
|
441 |
|
|
|
324 |
|
NGLs
transported-distribution lines (MBbl/d)
|
|
|
467 |
|
|
|
445 |
|
Conway-to-Mont
Belvieu OPIS average price differential
|
|
|
|
|
|
|
|
|
Ethane
($/gallon)
|
|
$ |
0.08 |
|
|
$ |
0.08 |
|
Realized
composite NGL net sales prices ($/gallon) (a)
(b)
|
|
$ |
0.99 |
|
|
$ |
0.88 |
|
Realized
condensate net sales price ($/Bbl) (a)
(b)
|
|
$ |
62.39 |
|
|
$ |
68.45 |
|
Realized
residue gas net sales price ($/MMBtu) (a)
(b)
|
|
$ |
5.20 |
|
|
$ |
3.58 |
|
Realized
gross processing spread
($/MMBtu) (a)
|
|
$ |
6.37 |
|
|
$ |
7.43 |
|
(a)
- Statistics relate to ONEOK Partners’ natural gas gathering and
processing business.
|
|
(b)
- Includes equity volumes only.
|
|
Commodity Price Risk - The
following tables set forth hedging information for ONEOK Partners’ natural gas
gathering and processing business for the periods indicated, as of April 28,
2010:
|
|
Nine
Months Ending
|
|
|
|
December
31, 2010 |
|
|
Volumes
Hedged
|
|
|
Average
Price
|
|
Percentage
Hedged
|
|
NGLs
(Bbl/d)
(a)
|
|
|
5,261 |
|
|
$ |
1.04 |
|
/
gallon
|
|
68 |
% |
Condensate
(Bbl/d)
(a)
|
|
|
1,648 |
|
|
$ |
1.81 |
|
/
gallon
|
|
76 |
% |
Total
(Bbl/d)
|
|
|
6,909 |
|
|
$ |
1.22 |
|
/
gallon
|
|
70 |
% |
Natural
gas
(MMBtu/d)
|
|
|
26,504 |
|
|
$ |
5.60 |
|
/
MMBtu
|
|
81 |
% |
(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
|
|
|
13 |
% |
Condensate
(Bbl/d)
(a)
|
|
596 |
|
|
$ |
2.12 |
|
/
gallon
|
|
|
26 |
% |
Total
(Bbl/d)
|
|
1,498 |
|
|
$ |
1.65 |
|
/
gallon
|
|
|
16 |
% |
Natural
gas
(MMBtu/d)
|
|
16,616 |
|
|
$ |
6.29 |
|
/
MMBtu
|
|
|
43 |
% |
(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 at March 31, 2010. 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 $1.1
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 $1.2
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.
Selected Financial Results -
The following table sets forth certain selected financial results for our
Distribution segment for the periods indicated:
|
|
Three
Months Ended
|
|
|
Variances
|
|
|
|
March
31,
|
|
|
2010
vs. 2009
|
|
Financial
Results
|
|
2010
|
|
|
2009
|
|
|
Increase
(Decrease)
|
|
|
|
(Millions
of dollars)
|
|
Gas
sales
|
|
$ |
962.5 |
|
|
$ |
813.2 |
|
|
$ |
149.3 |
|
18 |
% |
Transportation
revenues
|
|
|
29.6 |
|
|
|
26.5 |
|
|
|
3.1 |
|
12 |
% |
Cost
of gas
|
|
|
754.6 |
|
|
|
612.7 |
|
|
|
141.9 |
|
23 |
% |
Net
margin, excluding other revenues
|
|
|
237.5 |
|
|
|
227.0 |
|
|
|
10.5 |
|
5 |
% |
Other
revenues
|
|
|
9.3 |
|
|
|
12.0 |
|
|
|
(2.7 |
) |
(23 |
%) |
Net
margin
|
|
|
246.8 |
|
|
|
239.0 |
|
|
|
7.8 |
|
3 |
% |
Operating
costs
|
|
|
99.8 |
|
|
|
91.4 |
|
|
|
8.4 |
|
9 |
% |
Depreciation
and amortization
|
|
|
33.3 |
|
|
|
31.7 |
|
|
|
1.6 |
|
5 |
% |
Operating
income
|
|
$ |
113.7 |
|
|
$ |
115.9 |
|
|
$ |
(2.2 |
) |
(2 |
%) |
Capital
expenditures
|
|
$ |
31.4 |
|
|
$ |
44.7 |
|
|
$ |
(13.3 |
) |
(30 |
%) |
The
following table sets forth our net margin, excluding other revenues, by type of
customer, for the periods indicated:
|
|
Three
Months Ended
|
|
|
Variances
|
|
|
|
March
31,
|
|
|
2010
vs. 2009
|
|
Net
margin, excluding other revenues
|
|
2010
|
|
|
2009
|
|
|
Increase
(Decrease)
|
|
Gas
sales - Regulated
|
|
(Millions
of dollars)
|
|
Residential
|
|
$ |
165.0 |
|
|
$ |
156.5 |
|
|
$ |
8.5 |
|
|
5 |
% |
Commercial
|
|
|
36.4 |
|
|
|
37.4 |
|
|
|
(1.0 |
) |
|
(3 |
%) |
Industrial
|
|
|
0.7 |
|
|
|
0.8 |
|
|
|
(0.1 |
) |
|
(13 |
%) |
Wholesale
|
|
|
0.1 |
|
|
|
0.1 |
|
|
|
- |
|
|
0 |
% |
Public
Authority
|
|
|
1.5 |
|
|
|
1.3 |
|
|
|
0.2 |
|
|
15 |
% |
Gas
sales - Retail
|
|
|
4.2 |
|
|
|
4.4 |
|
|
|
(0.2 |
) |
|
(5 |
%) |
Net
margin on gas sales
|
|
|
207.9 |
|
|
|
200.5 |
|
|
|
7.4 |
|
|
4 |
% |
Transportation
margin
|
|
|
29.6 |
|
|
|
26.5 |
|
|
|
3.1 |
|
|
12 |
% |
Net
margin, excluding other revenues
|
|
$ |
237.5 |
|
|
$ |
227.0 |
|
|
$ |
10.5 |
|
|
5 |
% |
Net
margin increased for the three months ended March 31, 2010, compared with the
same period last year, due to the following:
·
|
an
increase of $3.1 million from various
riders;
|
·
|
an
increase of $2.7 million from higher transportation volumes;
and
|
·
|
an
increase of $2.4 million due to higher sales
volumes;
|
Operating
costs increased for the three months ended March 31, 2010, compared with the
same period last year, due to the following:
·
|
an
increase of $3.1 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 $2.9 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 $5.2 million and $11.0 million for new
business development for the three months ended March 31, 2010 and 2009,
respectively. Capital expenditures decreased for the three months
ended March 31, 2010, compared with the same period last year, primarily as a
result of a one-time payment to terminate vehicle and other equipment leases in
2009.
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
|
|
|
March
31,
|
|
Volumes
(MMcf)
|
2010
|
|
2009
|
|
Gas
sales
|
|
|
|
|
Residential
|
|
62,456 |
|
|
55,357 |
|
Commercial
|
|
17,178 |
|
|
15,752 |
|
Industrial
|
|
394 |
|
|
512 |
|
Wholesale
|
|
241 |
|
|
1,134 |
|
Public
Authority
|
|
1,243 |
|
|
847 |
|
Total
volumes sold
|
|
81,512 |
|
|
73,602 |
|
Transportation
|
|
62,154 |
|
|
55,964 |
|
Total
volumes delivered
|
|
143,666 |
|
|
129,566 |
|
|
|
Three
Months Ended
|
|
|
March
31,
|
Number
of Customers
|
|
2010
|
|
2009
|
|
Residential
|
|
1,930,678
|
|
1,913,351
|
|
Commercial
|
|
157,488
|
|
160,450
|
|
Industrial
|
|
1,296
|
|
1,368
|
|
Wholesale
|
|
35
|
|
27
|
|
Public
Authority
|
|
2,622
|
|
2,949
|
|
Transportation
|
|
9,406
|
|
10,746
|
|
Total
customers
|
|
2,101,525
|
|
2,088,891
|
|
Residential
volumes increased for the three months ended March 31, 2010, compared with the
same period last year, due to colder temperatures across our entire service
territory; however, the impact on margin increases was moderated by
weather-normalization mechanisms.
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 estimated impact on
2010 operating income is approximately $14 million. The new rates
went into effect on December 18, 2009, and include a higher customer charge that
reduces our volumetric exposure. Under a previous order, Oklahoma
Natural Gas is migrating 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.
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
December 2009, Kansas Gas Service filed an application with the KCC to become an
Efficiency Kansas Loan Program utility partner. The application seeks
to implement the KCC’s Efficiency Kansas Loan Program and a portfolio of energy
efficiency programs designed to encourage the purchase of efficient natural gas
appliances. Approval of the request would allow Kansas Gas Service to
recover its energy-efficiency program costs, and implement a revenue decoupling
mechanism that would maintain authorized revenues as determined in its latest
rate case.
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. We will file an appeal on or before
May 13, 2010, with the Railroad Commission of Texas. The Railroad
Commission will have approximately six months to render 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 months
ended March 31, 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 offer 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 service obligations or market needs.
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
|
|
|
Variances
|
|
|
March
31,
|
|
|
2010
vs. 2009
|
|
Financial
Results
|
|
2010
|
|
|
2009
|
|
|
Increase
(Decrease)
|
|
|
(Millions
of dollars)
|
|
Revenues
|
|
$ |
1,193.8 |
|
|
$ |
1,122.1 |
|
|
$ |
71.7 |
|
|
|
6 |
% |
Cost
of sales and fuel
|
|
|
1,083.2 |
|
|
|
1,063.9 |
|
|
|
19.3 |
|
|
|
2 |
% |
Net
margin
|
|
|
110.6 |
|
|
|
58.2 |
|
|
|
52.4 |
|
|
|
90 |
% |
Operating
costs
|
|
|
7.4 |
|
|
|
6.1 |
|
|
|
1.3 |
|
|
|
21 |
% |
Depreciation
and amortization
|
|
|
0.2 |
|
|
|
0.2 |
|
|
|
- |
|
|
|
0 |
% |
Operating
income
|
|
$ |
103.0 |
|
|
$ |
51.9 |
|
|
$ |
51.1 |
|
|
|
98 |
% |
The
following table sets forth our net margin by activity for the periods
indicated:
|
Three
Months Ended
|
|
|
Variances
|
|
|
March
31,
|
|
|
2010
vs. 2009
|
|
|
|
2010
|
|
|
2009
|
|
|
Increase
(Decrease)
|
|
|
(Millions
of dollars)
|
|
Marketing,
storage and transportation, gross
|
|
$ |
163.4 |
|
|
$ |
111.9 |
|
|
$ |
51.5 |
|
|
|
46 |
% |
Storage
and transportation costs
|
|
|
54.7 |
|
|
|
57.0 |
|
|
|
(2.3 |
) |
|
|
(4 |
%) |
Marketing,
storage and transportation, net
|
|
|
108.7 |
|
|
|
54.9 |
|
|
|
53.8 |
|
|
|
98 |
% |
Financial
trading, net
|
|
|
1.9 |
|
|
|
3.3 |
|
|
|
(1.4 |
) |
|
|
(42 |
%) |
Net
margin
|
|
$ |
110.6 |
|
|
$ |
58.2 |
|
|
$ |
52.4 |
|
|
|
90 |
% |
Marketing,
storage and transportation, gross, primarily includes 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 primarily include 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 increased for the three months ended March 31, 2010, compared with the
same period last year, due primarily to the following:
·
|
an
increase of $71.6 million from higher realized storage differentials and
marketing margins, net of hedging
activities;
|
·
|
an
increase of $4.8 million in transportation margins, net of hedging, due to
higher realized Rocky Mountain-to-Mid-Continent transportation margins,
resulting from the following:
|
-
|
realization
of more favorable hedges related to transportation differentials;
and
|
-
|
favorable
unrealized fair-value changes on non-qualifying economic hedge activity
and ineffectiveness on qualified hedges; partially offset
by
|
·
|
a
decrease of $22.6 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 $1.4 million in financial trading
margins.
|
Operating
costs increased due to higher employee-related costs.
Selected Operating Information
- The following table sets forth selected operating information for our Energy
Services segment for the periods indicated:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
Operating
Information
|
|
2010
|
|
2009
|
|
Natural
gas marketed (Bcf)
|
|
|
244 |
|
|
304 |
|
Natural
gas gross margin ($/Mcf)
|
|
$ |
0.46 |
|
$ |
0.20 |
|
Physically
settled volumes (Bcf)
|
|
|
485 |
|
|
609 |
|
Our
natural gas in storage at March 31, 2010, was 25.0 Bcf, compared with 45.5 Bcf
at March 31, 2009. At March 31, 2010, our total natural gas storage
capacity under lease was 82.8 Bcf, compared with 91.0 Bcf at March 31,
2009. Our natural gas storage capacity under lease had maximum
withdrawal capability of 2.3 Bcf/d and maximum injection capability of 1.4
Bcf/d. Our current natural gas transportation capacity is 1.7
Bcf/d.
Natural
gas volumes marketed and physically settled volumes decreased for the three
months ended March 31, 2010, compared with the same period last year, due
primarily to lower transported volumes. Transportation capacity in
certain markets was not utilized due to the economics of the transportation
spread.
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 liquidity. 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 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 2010,
ONEOK accessed the commercial paper markets to meet its short-term funding
needs. ONEOK Partners utilized the ONEOK Partners Credit Agreement to
fund its short-term liquidity needs. In February 2010, ONEOK Partners
issued common units. See discussion below under “ONEOK Partners’
Equity Issuance” for more information.
We expect
a moderate economic recovery in 2010, with inflationary pressures beginning in
2011. Although recent 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 during 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:
|
|
March
31,
|
|
December
31,
|
|
|
2010
|
|
2009
|
Long-term
debt
|
|
54%
|
|
57%
|
Equity
|
|
46%
|
|
43%
|
|
|
|
|
|
Debt
(including notes payable)
|
|
56%
|
|
61%
|
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:
|
|
March
31,
|
|
December
31,
|
|
|
2010
|
|
2009
|
Long-term
debt
|
|
39%
|
|
41%
|
Equity
|
|
61%
|
|
59%
|
|
|
|
|
|
Debt
(including notes payable)
|
|
39%
|
|
46%
|
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 ONEOK
Credit Agreement as discussed below. ONEOK also has a commercial
paper program that is utilized for short-term liquidity needs, and 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 and the ONEOK Partners Credit Agreement.
The total
amount of short-term borrowings authorized by ONEOK’s Board of Directors is $2.5
billion. At March 31, 2010, ONEOK had no commercial paper
outstanding, $37.0 million in letters of credit issued under the ONEOK Credit
Agreement and approximately $162.0 million of available cash and cash
equivalents. ONEOK had approximately $1.2 billion of credit available
at March 31, 2010, under the ONEOK Credit Agreement. As of March 31,
2010, ONEOK could have issued $3.6 billion of additional short- and long-term
debt under the most restrictive provisions contained in its various borrowing
agreements.
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 March 31, 2010, ONEOK Partners had $310.0 million in
borrowings outstanding under the ONEOK Partners Credit Agreement and
approximately $5.4 million of available cash and cash equivalents. As
of March 31, 2010, ONEOK Partners’ borrowing capacity was limited to $558
million of additional short- and long-term debt under the most restrictive
provisions contained in the ONEOK Partners Credit Agreement. At March
31, 2010, ONEOK Partners had a total of $24.2 million in letters of credit
issued outside the ONEOK Partners Credit Agreement.
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 March 31, 2010, ONEOK’s
stand-alone debt-to-capital ratio, as calculated under the terms of the ONEOK
Credit Agreement, was 38.5 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 March 31, 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.
ONEOK
Partners expects to refinance its $250 million senior notes due June 15, 2010,
with 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, borrowing under 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.
ONEOK
Partners’ $250 million and $225 million senior notes, due June 15, 2010, and
March 15, 2011, respectively, contain provisions that require ONEOK Partners to
offer to repurchase the senior notes at par value if its Moody’s
or S&P credit rating falls below investment grade (Baa3 for Moody’s or BBB-
for S&P) and the investment-grade rating is not reinstated within a period
of 40 days; however, once the $250 million 2010 senior notes have been retired,
whether by maturity, redemption or otherwise, ONEOK Partners will no longer have
any obligation to offer to repurchase the $225 million 2011 senior notes in the
event its credit rating falls below investment grade. Further, the
indentures governing ONEOK Partners’ senior notes due 2010 and 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 2010, 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 typically financed through
operating cash flows, short- and long-term debt and the issuance of
equity. Capital expenditures were $68.3 million and $243.0 million
for the three months ended March 31, 2010 and 2009, respectively. Of
these amounts, ONEOK Partners’ capital expenditures were $35.8 million and
$192.5 million for the three months ended March 31, 2010 and 2009,
respectively. Our capital expenditures are driven primarily by ONEOK
Partners’ capital projects. We classify expenditures that are
expected to generate additional revenue or significant operating efficiencies as
growth capital expenditures. Maintenance capital expenditures are
those required to maintain existing operations and do not generate additional
revenues.
Projected
2010 capital expenditures are significantly lower than 2009 capital
expenditures, due to various ONEOK Partners’ projects being completed or placed
in service during 2009. The following table sets forth our 2010
projected capital expenditures, excluding AFUDC:
2010
Projected Capital Expenditures
|
|
(Millions
of dollars)
|
ONEOK
Partners
|
$ |
362
|
|
Distribution
|
|
217
|
|
Other
|
|
24
|
|
Total
projected capital expenditures
|
$ |
603
|
|
Overland Pass Pipeline Company
- Overland Pass Pipeline Company is a joint venture between ONEOK Partners and a
subsidiary of The Williams Companies, Inc. (Williams). A subsidiary
of ONEOK Partners owns 99 percent of Overland Pass Pipeline Company and operates
the pipeline. On or before November 17, 2010, Williams has the option
to increase its ownership in Overland Pass Pipeline Company up to a total of 50
percent, with the purchase price being determined in accordance with the joint
venture’s operating agreement.
Credit Ratings - ONEOK’s and
ONEOK Partners’ credit ratings as of March 31, 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
commercial paper is rated P2 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 our credit ratings were downgraded, the
interest rates on our commercial paper borrowings and borrowings under the ONEOK
Credit Agreement would increase, and we could potentially
lose
access to the commercial paper market. Likewise, ONEOK Partners would
see increased borrowing costs under the ONEOK Partners Credit
Agreement. 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. An adverse rating change alone is not a
default under the ONEOK Credit Agreement or the ONEOK Partners Credit Agreement
but could trigger repurchase obligations with respect to certain ONEOK Partners’
long-term debt. See additional discussion about our credit ratings
under “Long-term Financing.”
If ONEOK
Partners’ repurchase obligations are triggered, it may not have sufficient cash
on hand to repurchase and repay any accelerated senior notes, which may cause it
to borrow money under its credit facilities, seek alternative financing sources
or sell assets to finance the repurchases and repayment. ONEOK
Partners could also face difficulties accessing capital or its borrowing costs
could increase, impacting its ability to obtain financing for acquisitions or
capital expenditures, to refinance indebtedness and to fulfill its debt
obligations.
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 March 31, 2010, ONEOK could have been required to
fund approximately $9.4 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 ONEOK Partners’ note repurchase obligations and 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 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 50 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.
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:
|
Three
Months Ended
|
|
|
Variances
|
|
|
March
31,
|
|
|
2010
vs. 2009
|
|
|
2010
|
|
|
2009
|
|
|
Increase
(Decrease)
|
|
|
(Millions
of dollars)
|
|
Total
cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
Operating
activities
|
$ |
558.7 |
|
|
$ |
790.9 |
|
|
$ |
(232.2 |
) |
|
(29 |
%) |
Investing
activities
|
|
(66.4 |
) |
|
|
(238.6 |
) |
|
|
172.2 |
|
|
72 |
% |
Financing
activities
|
|
(354.3 |
) |
|
|
(985.6 |
) |
|
|
631.3 |
|
|
64 |
% |
Change
in cash and cash equivalents
|
|
138.0 |
|
|
|
(433.3 |
) |
|
|
571.3 |
|
|
* |
|
Cash
and cash equivalents at beginning of period
|
|
29.4 |
|
|
|
510.1 |
|
|
|
(480.7 |
) |
|
(94 |
%) |
Cash
and cash equivalents at end of period
|
$ |
167.4 |
|
|
$ |
76.8 |
|
|
$ |
90.6 |
|
|
* |
|
*
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 $289.9 million for the three months ended March 31, 2010,
compared with $257.0 million for the same period in 2009. The
increase was due primarily to higher realized storage differentials and
marketing margins in our Energy Services segment and increased volumes gathered,
fractionated and transported, primarily associated with the completion of the
Arbuckle Pipeline, Piceance lateral and D-J Basin lateral, as well as new NGL
supply connections in our ONEOK Partners segment.
The
changes in operating assets and liabilities increased operating cash flows
$268.8 million for the three months ended March 31, 2010, compared with an
increase of $533.9 million for the same period in 2009, primarily as a result of
the following:
· a
decrease in cash collateral and margin requirements in our Energy Services
segment;
· 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 three months ended March 31,
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 - Net
repayments of notes payable were $0.6 billion during the first quarter of 2010,
compared with net repayments of $1.3 billion for the first quarter of
2009.
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.
In March
2009, ONEOK Partners completed an underwritten public offering of senior notes
and received proceeds totaling 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
February 2009, ONEOK repaid $100.0 million of maturing long-term debt with
available cash and short-term borrowings.
Dividends
paid were $0.44 per share during the first quarter of 2010, compared with
dividends of $0.40 per share during the first quarter of 2009.
Distributions
paid to limited partners by ONEOK Partners were $1.10 per unit during the first
quarter of 2010, compared with distributions of $1.08 per unit during the first
quarter of 2009.
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 United States Department of Transportation 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 emissions
are less than 5 million metric tons of carbon dioxide equivalents on an annual
basis. We expect to complete our annual estimate for 2009 during the
second quarter of 2010 and will post the information on our Web site when
available. 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 released 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. At this time, no legislation has been enacted as to what costs,
fees or expenses will be associated with any of these emissions.
The EPA
is proposing to finalize the “Tailoring Rule” that will regulate greenhouse gas
emissions at certain facilities that emit more than 25,000 tons of greenhouse
gas emissions per year. Under the Prevention of Significant
Deterioration requirement for existing facilities, upon making a major
modification to a facility, the facility would be required to obtain permits
that demonstrate they have installed the best available technology to control
greenhouse gas emissions. The rule is expected to be phased in
beginning January 2011 and could impact some of our facilities. At
this time, potential costs, fees or expenses associated with the proposed
“Tailoring Rule” are unknown.
In
addition, the EPA has issued a proposed 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 proposed 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, and one other has been given a preliminary 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. We expect to complete our
annual estimate for 2009 during the second quarter of 2010 and will post the
information on our Web site when available.
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
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;
|
·
|
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.
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 $139.6 million of net assets from
derivative instruments designated as either fair value or cash flow hedges at
March 31, 2010, and $0.6 million of deferred option premiums at March 31,
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
|
|
32 |
|
Fair
value of new derivatives entered into during the period
|
|
3,341 |
|
Other
changes in fair value
|
|
(1,296 |
) |
Net
fair value of derivatives outstanding at March 31, 2010
(a)
|
$ |
4,802 |
|
|
|
|
|
(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: $3.2 million matures
through
March 2011 and $1.6 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 $5.8 million and $7.0 million at
March 31, 2010 and 2009, respectively. The following table sets forth
the average, high and low VAR calculations for the periods
indicated:
|
Three
Months Ended
|
|
March
31,
|
Value-at-Risk
|
|
2010
|
|
|
2009
|
|
|
(Millions
of dollars)
|
Average
|
|
$ |
6.4 |
|
|
$ |
10.1 |
|
High
|
|
$ |
9.6 |
|
|
$ |
14.1 |
|
Low
|
|
$ |
3.9 |
|
|
$ |
6.2 |
|
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 March 31, 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 - We have made 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 first quarter ended March 31, 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.
Thomas F.
Boles, et al. v. El Paso Corporation, et al. (f/k/a Will Price, et al. v. Gas
Pipelines, et al., f/k/a Quinque Operating Company, et al. v. Gas
Pipelines, et al.), 26th
Judicial District, District Court of Stevens County, Kansas, Civil Department,
Case No. 99C30 (“Boles I”) - As previously reported, we, our division
Oklahoma Natural Gas, and four subsidiaries, ONEOK Partners, Mid-Continent
Market Center, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK WesTex
Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP,
successor to Koch Hydrocarbon Company), as well as approximately 225 other
defendants, are defendants in a lawsuit claiming underpayment of gas purchase
proceeds. The plaintiffs initially asserted that the defendants
understated both the volume and the heating content of the purchased gas, and
sought class certification for gas producers and royalty owners throughout the
United States. The Court refused to certify the class and the
plaintiffs amended their petition to limit the purported class to gas producers
and royalty owners in Kansas, Colorado and Wyoming, and limited the claim to
undermeasurement of volume. On September 18, 2009, the Court denied
the plaintiffs’ motions for class certification, which, in effect, limited the
named plaintiffs to pursuing individual claims against only those defendants who
purchased or measured their gas. On October 2, 2009, the plaintiffs
filed a motion for reconsideration of the Court’s denial of class
certification. On March 31, 2010, the Court denied the plaintiffs
motion for reconsideration.
Thomas F.
Boles, et al. v. El Paso Corporation, et al. (f/k/a Will Price and Stixon
Petroleum, et al. v. Gas Pipelines, et al.), 26th Judicial District, District
Court of Stevens County, Kansas, Civil Department, Case No. 03C232 (“Boles II”)
- As previously reported, 21 groups of defendants, including us, our
division Oklahoma Natural Gas, four subsidiaries of ONEOK Partners,
Mid-Continent Market Center, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK
WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch
Hydrocarbon, LP, successor to Koch Hydrocarbon Company), are defendants in a
lawsuit claiming underpayment of gas producers and royalty owners by allegedly
understating the heating content of purchased gas in Kansas, Colorado and
Wyoming. This action was filed by the plaintiffs after the Court
denied the initial motion for class status in Boles I, and Boles II was
consolidated with Boles I to determine whether either or both cases may properly
be certified. On September 18, 2009, the Court denied the plaintiffs’
motions for class certification, which, in effect, limited the named plaintiffs
to pursuing individual claims against only those defendants who purchased or
measured their gas. On October 2, 2009, the plaintiffs filed a motion
for reconsideration of the Court’s denial of class certification. On
March 31, 2010, the Court denied the plaintiffs motion for
reconsideration.
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 February 2, 2010, the Missouri Court of Appeals, Western
District, denied the plaintiff’s motion for a rehearing on the dismissal granted
in the Missouri Public Service
Commission v. ONEOK, Inc., et al., case. On April 20, 2010,
the Missouri Supreme Court granted the application of the plaintiff to transfer
the case to the Missouri Supreme Court for review of the decision of the
Missouri Court of Appeals that affirmed the dismissal of the case by the trial
court. On April 21, 2010, the U.S. Court of Appeals for the Ninth
Circuit reversed the dismissal of the Sinclair case and remanded it
back to the multi-district litigation matter MDL-1566 in the U.S. District Court
for the District of Nevada for further proceedings. On April 23,
2010, the Tennessee Supreme Court reversed the decision of the Tennessee Court
of Appeals in the Leggett case and dismissed
the claims of the plaintiffs. We continue to vigorously defend
against the claims involved in each of the remaining 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.
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January
1-31, 2010
|
3,106
|
(a),
(b)
|
|
$19.64
|
|
|
-
|
|
|
|
-
|
|
February
1-28, 2010
|
7,589
|
(a)
|
|
$23.92
|
|
|
-
|
|
|
|
-
|
|
March
1-31, 2010
|
105,319
|
(a)
|
|
$27.86
|
|
|
-
|
|
|
|
-
|
|
Total
|
116,014
|
|
|
$27.39
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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:
|
|
|
|
|
|
3,000
shares for the period of January 1-31, 2010
|
|
|
|
|
|
|
|
|
|
|
7,589
shares for the period of February 1-28, 2010
|
|
|
|
|
|
|
|
|
105,319
shares for the period of March 1-31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b)
- Includes shares repurchased directly from employees, pursuant to our
Employee Stock Award Program, as follows:
|
106
shares for the period January 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, and, 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.
The
following exhibits are filed as part of this Quarterly Report:
Exhibit
No. Exhibit
Description
|
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 months ended March 31, 2010 and 2009;
(iii) Consolidated Balance Sheets at March 31, 2010 and December 31,
2009; (iv) Consolidated Statements of Cash Flows for the three months ended
March 31, 2010 and 2009; (v) Consolidated Statement of Shareholders’ Equity
for the three months ended March 31, 2010; (vi) Consolidated Statements of
Comprehensive Income for the three months ended March 31, 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.
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.
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ONEOK,
Inc.
Registrant
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Date:
April 29, 2010
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By:
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/s/
Curtis L. Dinan
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|
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Curtis
L. Dinan
Senior
Vice President,
Chief
Financial Officer and Treasurer
(Principal
Financial Officer)
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