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OGE ENERGY CORP. - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations.
(Edgar Glimpses Via Acquire Media NewsEdge) Introduction
The Company is an energy and energy services provider offering physical delivery
and related services for both electricity and natural gas primarily in the south
central United States. The Company conducts these activities through three
business segments: (i) electric utility, (ii) natural gas transportation and
storage and (iii) natural gas gathering and processing.
The electric utility segment generates, transmits, distributes and sells
electric energy in Oklahoma and western Arkansas. Its operations are conducted
through OG&E and are subject to regulation by the OCC, the APSC and the FERC.
OG&E was incorporated in 1902 under the laws of the Oklahoma Territory. OG&E is
the largest electric utility in Oklahoma and its franchised service territory
includes the Fort Smith, Arkansas area. OG&E sold its retail natural gas
business in 1928 and is no longer engaged in the natural gas distribution
business.
Enogex is a provider of integrated natural gas midstream services. Enogex is
engaged in the business of gathering, processing, transporting and storing
natural gas. Most of Enogex's natural gas gathering, processing, transportation
and storage assets are strategically located in the Arkoma and Anadarko basins
of Oklahoma and the Texas Panhandle. During the third quarter of 2012, the
operations and activities of EER were fully integrated with those of Enogex
through the creation of a new commodity management organization. This new
organization is intended to facilitate the execution of Enogex's strategy
through an enhanced focus on asset optimization and active management of its
growing natural gas, NGLs and condensate positions. The operations of EER,
including asset management activities, have been included in the natural gas
transportation and storage segment and have been restated for all prior periods
presented. Enogex's operations are now organized into two business segments: (i)
natural gas transportation and storage and (ii) natural gas gathering and
processing. At December 31, 2012, OGE Energy indirectly owns a 79.9 percent
membership interest in Enogex Holdings, which in turn owns all of the membership
interests in Enogex LLC.
Overview
Company Strategy
The Company's mission is to fulfill its critical role in the nation's electric
utility and natural gas midstream pipeline infrastructure and meet individual
customers' needs for energy and related services focusing on safety, efficiency,
reliability, customer service and risk management. The Company's corporate
strategy is to continue to maintain its existing business mix and diversified
asset position of its regulated electric utility business and unregulated
natural gas midstream business while providing competitive energy products and
services to customers primarily in the south central United States as well as
seeking growth opportunities in both businesses.
OG&E is focused on increased investment to preserve system reliability and meet
load growth by adding and maintaining infrastructure equipment and replacing
aging transmission and distribution systems. OG&E expects to maintain a diverse
generation portfolio while remaining environmentally responsible. OG&E is
focused on maintaining strong regulatory and legislative relationships for the
long-term benefit of its customers. In an effort to encourage more efficient use
of electricity, OG&E is also providing energy management solutions to its
customers through the Smart Grid program that utilizes newer technology to
improve operational and environmental performance as well as allow customers to
monitor and manage their energy usage, which should help reduce demand during
critical peak times, resulting in lower capacity requirements. If these
initiatives are successful, OG&E believes it may be able to defer the
construction or acquisition of any incremental fossil fuel generation capacity
until 2020. The Smart Grid program also provides benefits to OG&E, including
more efficient use of its resources and access to increased information about
customer usage, which should enable OG&E to have better distribution system
planning data, better response to customer usage questions and faster detection
and restoration of system outages. As the Smart Grid platform matures, OG&E
anticipates providing new products and services to its customers. In addition,
OG&E is also pursuing additional transmission-related opportunities within the
SPP.
Enogex's business plan entails growing its businesses and providing attractive
financial returns through efficient operations and effective commercial
management of its assets. Enogex also plans to capture growth opportunities
through expansion projects, increased utilization of existing assets and through
acquisitions (including joint ventures) in and around its footprint and
attracting new customers. In addition, Enogex is seeking to geographically
diversify its gathering, processing and transportation businesses principally by
expanding into other areas that are complementary with the Company's
capabilities. Enogex expects to accomplish this diversification by undertaking
organic growth projects and through acquisitions.
Additionally, the Company wants to achieve a premium valuation of its businesses
relative to its peers, grow earnings per share with a stable earnings pattern,
create a high performance culture and achieve desired outcomes with target
stakeholders.
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The Company's financial objectives include a long-term annual earnings growth
rate of five to seven percent on a weather-normalized basis, maintaining a
strong credit rating as well as increasing the dividend to meet the Company's
dividend payout objectives. The Company's target payout ratio is to pay out
dividends no more than 60 percent of its normalized earnings on an annual basis.
The target payout ratio has been determined after consideration of numerous
factors, including the largely retail composition of the Company's shareholder
base, the Company's financial position, the Company's growth targets, the
composition of the Company's assets and investment opportunities. The Company
believes it can accomplish these financial objectives by, among other things,
pursuing multiple avenues to build its business, maintaining a diversified asset
position, continuing to develop a wide range of skills to succeed with changes
in its industries, providing products and services to customers efficiently,
managing risks effectively and maintaining strong regulatory and legislative
relationships.
Summary of Operating Results
2012 compared to 2011. Net income attributable to OGE Energy was $355.0 million,
or $3.58 per diluted share, in 2012 as compared to $342.9 million, or $3.45 per
diluted share, in 2011. The increase in net income attributable to OGE Energy of
$12.1 million, or 3.5 percent, or $0.13 per diluted share, in 2012 as compared
to 2011 was primarily due to:
• an increase in net income at OG&E of $17.0 million, or 6.5 percent,
or $0.18 per diluted share of the Company's common stock, primarily
due to a higher gross margin and lower income tax expense. The
higher gross margin was primarily due to increased recovery of
investments and increased transmission revenue partially offset by
milder weather in OG&E's service territory. These increases were
partially offset by higher other operation and maintenance expense,
higher depreciation and amortization expense, lower allowance for
equity funds used during construction and higher interest expense;
• a decrease in net income at Enogex of $8.1 million, or 9.9 percent,
or $0.08 per diluted share of the Company's common stock, primarily
due to higher other operation and maintenance expense, higher
depreciation and amortization expense, lower other income primarily
due to the recognition of a gain related to the sale of the Harrah
processing plant and the associated Wellston and Davenport gathering
assets in 2011, higher interest expense and OGE Energy's lower
membership interest in Enogex Holdings. These decreases were
partially offset by a higher gross margin related to (i) increased
gathering rates and volumes associated with ongoing expansion
projects and increased volumes from gas gathering assetsacquired in
November 2011 and August 2012 and (ii) increased inlet volumes
partially offset by lower average natural gas and NGLs prices. Also
having a positive impact on net income was a higher gain on
insurance proceeds in 2012 and an impairment related to the Atoka
processing plant in 2011; and
• an increase in net income at OGE Energy of $3.2 million, or $0.03
per diluted share of the Company's common stock, primarily due to
higher other income due to a decrease in deferred compensation
losses partially offset by higher interest expense and a lower
income tax benefit in 2012.
Non-Recurring Items. During 2012, Enogex had an increase in net income of $4.6
million due to a gain on insurance proceeds related to the reimbursement of
costs incurred to replace the damaged train at the Cox City natural gas
processing plant partially offset by a decrease in net income of $2.1 million
related to sales taxes on the assets acquired in the gas gathering acquisitions
in August 2012, as discussed in Note 3 of Notes to Consolidated Financial
Statements, which Enogex does not consider to be reflective of its ongoing
performance. During 2011, Enogex had an increase in net income of $2.3 million
relating to the sale of the Harrah processing plant and the associated Wellston
and Davenport gathering assets in April 2011, which Enogex does not consider to
be reflective of its ongoing performance.
2011 compared to 2010. Net income attributable to OGE Energy was $342.9 million,
or $3.45 per diluted share, in 2011 as compared to $295.3 million, or $2.99 per
diluted share, in 2010. Included in net income attributable to OGE Energy in
2010 was a one-time, non-cash charge of $11.4 million, or $0.11 per diluted
share, related to the elimination of the tax deduction for the Medicare Part D
subsidy (as previously reported in the Company's Form 10-Q for the quarter ended
March 31, 2011). The increase in net income attributable to OGE Energy of $47.6
million, or 16.1 percent, or $0.46 per diluted share, in 2011 as compared to
2010 was primarily due to:
• an increase in net income at OG&E of $47.6 million or 22.1 percent,
or $0.47 per diluted share of the Company's common stock, primarily
due to a higher gross margin primarily from warmer weather in OG&E's
service territory partially offset by higher other operation and
maintenance expense, higher interest expense and higher income tax
expense. Income tax expense was higher due to higher pre-tax income
which more than offset the effects of the Medicare Part D subsidy
discussed above;
• a decrease in net income at Enogex of $8.9 million or 9.8 percent,
or $0.09 per diluted share of the Company's common stock, primarily
due to higher other operation and maintenance expense and OGE
Energy's lower membership interest in Enogex Holdings partially
offset by a higher gross margin primarily from higher NGLs
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prices and increased gathered volumes associated with ongoing expansion
projects, the recognition of a gain related to the sale of the Harrah processing
plant and the associated Wellston and Davenport gathering assets, lower interest
expense and lower income tax expense related to the Medicare Part D subsidy
discussed above; and
• an increase in the net income at OGE Energy of $8.9 million or 77.4
percent or $0.08 per diluted share of the Company's common stock,
primarily due to lower other operation and maintenance expense, a
decrease in charitable contributions in 2011 and a higher income tax
benefit related to the Medicare Part D subsidy discussed above.
Non-Recurring Item. During 2011, Enogex had an increase in net income of $2.3
million relating to the sale of the Harrah processing plant and the associated
Wellston and Davenport gathering assets in April 2011, which Enogex does not
consider to be reflective of its ongoing performance.
Timing Item. Enogex's net income in 2011 was $82.2 million, which included a
loss of $2.6 million resulting from recording Enogex's natural gas storage
inventory at the lower of cost or market value. The offsetting gains from the
sale of withdrawals from inventory were realized during the first quarter of
2012.
Recent Developments and Regulatory Matters
OG&E SPP Transmission Projects
In 2007, the SPP notified OG&E to construct 44 miles of a new 345 kilovolt
transmission line originating at OG&E's existing Sooner 345 kilovolt substation
and proceeding generally in a northerly direction to the Oklahoma/Kansas
Stateline (referred to as the Sooner-Rose Hill project). At the Oklahoma/Kansas
Stateline, the line connects to the companion line constructed in Kansas by
Westar Energy. The transmission line was placed in service in April 2012. The
total capital expenditures associated with this project were $45 million.
In January 2009, OG&E received notification from the SPP to begin construction
on 50 miles of a new 345 kilovolt transmission line and substation upgrades at
OG&E's Sunnyside substation, among other projects. In April 2009, Western
Farmers Electric Cooperative assigned to OG&E the construction of 50 miles of
line designated by the SPP to be built by Western Farmers Electric Cooperative.
The new line extends from OG&E's Sunnyside substation near Ardmore, Oklahoma,
123.5 miles to the Hugo substation owned by Western Farmers Electric Cooperative
near Hugo, Oklahoma. The transmission line was completed in April 2012. The
total capital expenditures associated with this project were $157 million.
As discussed in Note 17 of Notes to Consolidated Financial Statements, the OCC
approved a settlement agreement in OG&E's 2011 Oklahoma rate case filing that
included an expedited procedure for recovering the costs of the two projects.
On July 31, 2012, OG&E filed an application with the OCC requesting an order
authorizing recovery for the two projects through the SPP transmission systems
additions rider. On October 2, 2012, all parties signed a settlement agreement
in this matter which stated: (i) the parties agree not to oppose requested
relief sought by OG&E, (ii) OG&E will host meetings to discuss the SPP's
transmission planning process, including any future transmission projects for
which OG&E has received a notice to construct from the SPP, and (iii) there will
be opportunities for parties to provide input related to transmission planning
studies that the SPP performs to identify future transmission projects. On
October 25, 2012, the OCC issued an order approving the settlement agreement and
granting OG&E cost recovery for the two projects. OG&E initiated cost recovery
beginning with the first billing cycle in November 2012.
OG&E Demand and Energy Efficiency Program Filing
On July 2, 2012, OG&E filed an application with the OCC requesting approval of
OG&E's 2013 demand portfolio, the authorization to recover the program costs,
lost revenues associated with any achieved energy, demand savings and
performance based incentives through the demand program rider and the recovery
of costs associated with research and development investments. On July 16, 2012,
OG&E filed an amended application which modified various calculations to reflect
the rate of return authorized by the OCC in OG&E's 2011 rate case order and
provided for consideration of a peak time rebate program. On December 20, 2012,
the OCC approved a settlement with all parties in this matter. Key terms of the
settlement included (i) approval of the program budgets proposed by OG&E and an
additional amount of approximately $7 million over the three-year period for the
energy efficiency programs, (ii) approval of OG&E's proposed Demand Program
Rider tariff, (iii) the recovery through the Demand Program Rider of the
increased program costs and the net lost revenues, incentives and research and
development investments requested by OG&E, with the exception of lost revenues
resulting from the Integrated Volt Var Control program (automated intelligence
to control voltage and power on the distribution lines) and incentives for the
SmartHours® and Integrated Volt Var Control demand response programs, (iv)
recovery of the program costs on a levelized basis over the three-year period,
(v)
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consideration of implementing a peak time rebate program in 2015 and (vi) the
periodic filing of additional reports. The Demand Program Rider became effective
on January 1, 2013.
OG&E Fuel Adjustment Clause Review for Calendar Year 2010
The OCC routinely reviews the costs recovered from customers through OG&E's fuel
adjustment clause. On August 19, 2011, the OCC Staff filed an application to
review OG&E's fuel adjustment clause for calendar year 2010, including the
prudence of OG&E's electric generation, purchased power and fuel procurement
costs. OG&E responded by filing direct testimony and the minimum filing review
package on October 18, 2011. On September 26, 2012, the administrative law judge
recommended that the OCC find that for the calendar year 2010 OG&E's generation,
purchase power and fuel procurement processes and costs, including the cost of
replacement power for the Sooner 2 outage, were prudent and no disallowance (as
discussed below) for any of these expenses is warranted. On January 31, 2013,
the OCC issued an order approving the administrative law judge's recommendation.
Previously, the Oklahoma Industrial Energy Consumers recommended that the OCC
disallow recovery of approximately $44 million of costs previously recovered
through OG&E's fuel adjustment clause. These recommendations were based on
allegations that OG&E's lower cost coal-fired generation was underutilized, that
OG&E failed to aggressively pursue purchasing power at a cost lower than its
marginal cost of generation and that OG&E should be found imprudent related to
an unplanned outage at OG&E's Sooner 2 coal unit in November and December 2010.
Previously, the OCC Staff recommended approval of OG&E's actions related to
utilization of coal plants and practices related to purchasing power but
recommended that OG&E refund $3 million to customers because of the Sooner 2
outage.
Texas Panhandle Gathering Divestiture
On January 2, 2013, Enogex and one of its five largest customers entered into
new agreements, effective January 1, 2013, relating to the customer's gathering
and processing volumes on the Texas portion of Enogex's system. The effects of
this new arrangement are (i) a fixed fee processing agreement replaces the
previous keep-whole agreement, (ii) the acreage dedicated by the customer to
Enogex for gathering and processing in Texas has been increased for an extended
term and (iii) the sale by Enogex of certain gas gathering assets in the Texas
Panhandle portion of Enogex's system to this customer for cash proceeds of
approximately $35 million. The sale of these assets was approved by the
Company's and Enogex's Board of Directors in November 2012, therefore these
assets were classified as held for sale on the Company's Consolidated Balance
Sheet at December 31, 2012. Enogex expects to recognize a pre-tax gain of
approximately $10 million in the first quarter of 2013 in its natural gas
gathering and processing segment from the sale of these assets.
Enogex Western Oklahoma / Texas Panhandle Natural Gas Gathering and Processing
System Expansions
In August 2012, Enogex completed construction of its cryogenic processing plant
in Wheeler County, Texas, which added 200 MMcf/d of rich gas processing capacity
to Enogex's system, and is supported by the installation of 9,400 horsepower of
field compression, as well as 6,000 horsepower of inlet compression to
facilitate additional flexibility in the operation of Enogex's "super-header"
gathering system. The remainder of the inlet compression facilities is expected
to be in service during the second quarter of 2013.
In support of significant long-term acreage dedications from its customers in
the area, Enogex has expanded its gathering infrastructure in western Oklahoma
and the Texas Panhandle. These expansions included the installation of 39,700
horsepower of low pressure compression and 235 miles of gathering pipe across
the area, which was completed during the third quarter of 2012.
In support of significant long-term acreage dedications from its customers in
the area, Enogex is expanding its gathering infrastructure in southern Oklahoma.
The initial phase of these expansions include the installation of approximately
20,000 horsepower of compression and approximately 100 miles of gathering
pipeline, which are expected to be in service by the end of the first quarter of
2013. The remainder of the expansion includes the installation of approximately
50,000 horsepower of compression and approximately 300 miles of gathering
pipeline, which are expected to be in service by the end of 2013.
Enogex is constructing a cryogenic processing plant in Custer County, Oklahoma,
which is expected add 200 MMcf/d of natural gas processing capacity to Enogex's
system, and is expected to be supported by the installation of 6,000 horsepower
of inlet compression and four miles of transmission pipeline. This plant will be
connected to the Enogex "super-header" gathering system and is expected to be in
service by the end of 2013.
The capital expenditures related to the above projects are presented in the
summary of capital expenditures for known and committed projects in "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources - Future Capital Requirements and
Financing Activities."
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--------------------------------------------------------------------------------Gas Gathering Acquisitions
On August 1, 2012, Enogex entered into agreements with Chesapeake Midstream Gas
Services, L.L.C. and Mid-America Midstream Gas Services, L.L.C., wholly-owned
subsidiaries of Access Midstream Partners, L.P. and Chesapeake Midstream
Development, L.P., respectively, pursuant to which Enogex agreed to acquire
approximately 235 miles of natural gas gathering pipelines, right-of-ways and
certain other midstream assets that provide natural gas gathering services in
the greater Granite Wash area. The transactions closed on August 31, 2012. The
aggregate purchase price for these transactions was approximately $78.6 million
including reimbursement for certain permitted capital expenditures incurred
during the period beginning June 1, 2012 and ending August 31, 2012. Enogex
utilized cash generated from operations and bank borrowings to fund the
purchase. In addition, Enogex also incurred acquisition-related costs of $3.5
million for sales taxes on acquired assets, which are included in taxes other
than income. Enogex expects the purchase price allocations to be completed by
the end of the first quarter of 2013. The Company believes that the acquisition
transactions will provide Enogex with key new opportunities in the greater
Granite Wash area.
In connection with these agreements, Enogex entered into a gas gathering and
processing agreement with Chesapeake effective September 1, 2012 pursuant to
which Enogex began providing fee-based natural gas gathering, compression,
processing and transportation services to Chesapeake with respect to certain
acreage dedicated by Chesapeake.
The capital expenditures related to the above agreements are presented in the
summary of capital expenditures for known and committed projects in "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources - Future Capital Requirements and
Financing Activities."
2013 Outlook
The Company's 2013 earnings guidance is between approximately $335 million and
$360 million of net income, or $3.35 to $3.60 per average diluted share.
Key assumptions for 2013 include:
Consolidated OGE
• Approximately 100 million average diluted shares outstanding;
• An effective tax rate of approximately 30 percent; and
• A projected loss at the holding company between approximately $2
million and $4 million, or $0.02 to $0.04 per diluted share,
primarily due to interest expense relating to long andshort-term
debt borrowings partially offset by tax deductions.
OG&E
The Company projects OG&E to earn approximately $280 million to $290 million or
$2.80 to $2.90 per average diluted share in 2013 and is based on the following
assumptions:
• Normal weather patterns are experienced for the remainder of the year;
• Gross margin on revenues of approximately $1.290 billion to $1.295
billion based on sales growth of approximately 1.5 percent on a
weather-adjusted basis;
• Approximately $75 million of gross margin is primarily
attributed to regionally allocated transmission projects;
• Operating expenses of approximately $770 million to $780 million,
with operation and maintenance expenses comprising 57 percent of the
total;
• Interest expense of approximately $130 million to $135million which
assumes a $3 million allowance for borrowed funds used during
construction reduction to interest expense and $250 million of
long-term debt issued in the first half of 2013;
• Allowance for equity funds used during construction ofapproximately
$10 million; and
• An effective tax rate of approximately 28 percent.
OG&E has significant seasonality in its earnings. OG&E typically shows minimal
earnings in the first and fourth quarters with a majority of earnings in the
third quarter due to the seasonal nature of air conditioning demand.
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--------------------------------------------------------------------------------Enogex
The Company projects Enogex to earn approximately $55 million to $75 million, or
$0.55 to $0.75 per average diluted share and EBITDA between $213 million and
$241 million, in 2013 net of noncontrolling interest, and is based on the
following assumptions:
• Total Enogex anticipated gross margin of between approximately $470
million and $500 million. The gross margin assumption includes:
• Natural gas transportation and storage gross margincontribution of
between approximately $130 million and $140 million, of which 83
percent is attributable to the transportation business;
• Natural gas gathering and processing gross margincontribution of
between approximately $340 million and $360 million, of which 51
percent is attributable to the processing business;
• Key factors affecting the natural gas gathering andprocessing gross
margin forecast are:
• Assumed increase of approximately 10 to 15 percent in gathered
volumes over 2012;
• Assumed increase of approximately 10 to 15 percent in
processable* volumes over 2012;
• At the midpoint of Enogex's natural gas gathering and processing
assumption Enogex has assumed:
• An average processing contract mix of 48 percent fixed-fee, 23
percent percent-of-liquids, 19 percentpercent-of-proceeds and
10 percent keep-whole;
• Average natural gas price of $3.38 per MMBtu in 2013;
• Average NGLs price of $0.82 per gallon in 2013;
• Average price per gallon of condensate of $2.13 in 2013;
• Ethane is projected to be in rejection for 2013;
• Approximately 50 percent of NGLs volumes are expected to flow
to Mt. Belvieu; and
• A 10 percent change in the average NGLs price for the entire
year impacts net income approximately $5 million;
• Enogex has assumed operating expenses of approximately $325 million to
$335 million, with operation and maintenance expenses comprising 54
percent of the total;
• A pre-tax gain of approximately $10 million associated with asset sales
in the first quarter of 2013;
• Interest expense of approximately $30 million to $35 million;
• An effective tax rate of approximately 38 percent; and
• ArcLight group will own approximately 22 percent of Enogex Holdings by
the end of 2013.
2014 Volume projections for Enogex:
• Assumed increase of approximately five to 10 percent in gathered volumes
over 2013; and
• Assumed increase of approximately 10 to 20 percent in processable* volumes
over 2013.
* Processable volumes are the natural gas production that are on Enogex's
gathering systems that are available to be processed, some of which is moved off
of the system and is not processed under one of Enogex's processing agreements.
Processable volumes include condensate volumes which are captured in the
gathering pipeline and therefore not included in plant inlet volumes.
EBITDA is a supplemental non-GAAP financial measure used by external users of
the Company's financial statements such as investors, commercial banks and
others; therefore, the Company has included the table below which provides a
reconciliation of projected EBITDA to projected net income attributable to
Enogex Holdings at the midpoint of Enogex Holdings' earnings assumptions for
2013, which does not include the effect of income taxes whereas OGE Energy's
portion of Enogex Holdings' net income included in OGE Energy's earnings
guidance does reflect the effect of income taxes. Enogex Holding's net income
shown in the EBITDA table does not include the effect of income taxes because
Enogex Holdings is a partnership and is not subject to income taxes. Each
partner is responsible for paying their own income taxes. For a discussion of
the reasons for the use of EBITDA, as well as its limitations as an analytical
tool, see "Non-GAAP Financial Measure" below.
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Reconciliation of projected EBITDA to projected net income attributable to
Enogex Holdings
Twelve Months Ended
December 31, 2013
(In millions) (A)(B)
Net income attributable to Enogex Holdings $ 132
Add:
Interest expense, net 33
Depreciation and amortization expense (C) 123
EBITDA $ 288
OGE Energy's portion $ 228
(A) Based on the midpoint of Enogex Holdings' earnings guidance for 2013.
(B) As of November 1, 2010, Enogex Holdings' earnings are no longer subject to
tax (other than Texas state margin taxes) and are taxable at the individual
partner level.
(C) Includes amortization of certain customer-based intangible assets associated
with the acquisition from Cordillera in November 2011, which is included in
gross margin for financial reporting purposes.
Results of Operations
The following discussion and analysis presents factors that affected the
Company's consolidated results of operations for the years ended December 31,
2012, 2011 and 2010 and the Company's consolidated financial position at
December 31, 2012 and 2011. The following information should be read in
conjunction with the Consolidated Financial Statements and Notes thereto. Known
trends and contingencies of a material nature are discussed to the extent
considered relevant.
Year ended December 31 (In millions except per share 2012 2011 2010
data)
Operating income $ 676.9 $ 646.7 $ 593.9
Net income attributable to OGE Energy $ 355.0 $ 342.9 $ 295.3
Basic average common shares outstanding 98.6 97.9 97.3
Diluted average common shares outstanding 99.1 99.2 98.9
Basic earnings per average common share attributable to
OGE Energy common shareholders
$ 3.60 $ 3.50 $ 3.03
Diluted earnings per average common share attributable
to OGE Energy common shareholders
$ 3.58 $ 3.45 $ 2.99
Dividends declared per common share $ 1.5950 $ 1.5175 $ 1.4625
In reviewing its consolidated operating results, the Company believes that it is
appropriate to focus on operating income as reported in its Consolidated
Statements of Income as operating income indicates the ongoing profitability of
the Company excluding the cost of capital and income taxes.
Operating Income (Loss) by Business Segment
Year ended December 31 (In millions) 2012 2011 2010
OG&E (Electric Utility)
$ 489.4 $ 472.3 $ 413.7
Enogex (Natural Gas Midstream Operations)
Natural gas transportation and storage (A) 45.1 56.4 60.4
Natural gas gathering and processing 140.5 118.7 123.9
Other Operations (B)
1.9 (0.7 ) (4.1 )
Consolidated operating income $ 676.9 $ 646.7 $ 593.9
(A) During the third quarter of 2012, the operations and activities of EER were
fully integrated with those of Enogex through the creation of a new commodity
management organization. The operations of EER, including asset management
activities, have been included in the natural gas transportation and storage
segment and have been restated for all prior periods presented.
(B) Other Operations primarily includes the operations of the holding company and
consolidating eliminations.
The following operating income analysis by business segment includes
intercompany transactions that are eliminated in the Consolidated Financial
Statements.
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OG&E (Electric Utility)
Year ended December 31 (Dollars in millions) 2012 2011 2010
Operating revenues $ 2,141.2 $ 2,211.5 $ 2,109.9
Cost of goods sold 879.1 1,013.5 1,000.2
Gross margin on revenues 1,262.1 1,198.0 1,109.7
Other operation and maintenance 446.3 436.0 418.1
Depreciation and amortization 248.7 216.1 208.7
Taxes other than income 77.7 73.6 69.2
Operating income 489.4 472.3 413.7
Interest income 0.2 0.5 0.1
Allowance for equity funds used during construction 6.2 20.4 11.4
Other income 8.0 8.0 6.5
Other expense 4.3 8.4 1.6
Interest expense 124.6 111.6 103.4
Income tax expense 94.6 117.9 111.0
Net income $ 280.3 $ 263.3 $ 215.7
Operating revenues by classification
Residential $ 878.0 $ 943.5 $ 894.8
Commercial 523.5 531.3 521.0
Industrial 206.8 216.0 212.5
Oilfield 163.4 165.1 162.8
Public authorities and street light 202.4 207.4 200.8
Sales for resale 54.9 65.3 65.8
System sales revenues 2,029.0 2,128.6 2,057.7
Off-system sales revenues 36.5 36.2 21.7
Other 75.7 46.7 30.5
Total operating revenues $ 2,141.2 $ 2,211.5 $ 2,109.9
MWH sales by classification (In millions)
Residential 9.1 9.9 9.6
Commercial 7.0 6.9 6.7
Industrial 4.0 3.9 3.8
Oilfield 3.3 3.2 3.1
Public authorities and street light 3.3 3.2 3.0
Sales for resale 1.3 1.4 1.4
System sales 28.0 28.5 27.6
Off-system sales 1.4 1.0 0.5
Total sales 29.4 29.5 28.1
Number of customers 798,110 789,146 782,558
Weighted-average cost of energy per kilowatt-hour - cents
Natural gas 2.930 4.328 4.638
Coal 2.310 2.064 1.911
Total fuel 2.437 2.897 3.012
Total fuel and purchased power 2.806 3.215 3.309
Degree days (A)
Heating - Actual 2,667 3,359 3,528
Heating - Normal 3,349 3,631 3,631
Cooling - Actual 2,561 2,776 2,328
Cooling - Normal 2,092 1,911 1,911
(A) Degree days are calculated as follows: The high and low degrees of a
particular day are added together and then averaged. If the calculated
average is above 65 degrees, then the difference between the calculated
average and 65 is expressed as cooling degree days, with each degree of
difference equaling one cooling degree day. If the calculated average is
below 65 degrees, then the difference between the calculated average and 65
is expressed as heating degree days, with each degree of difference equaling
one heating degree day. The daily calculations are then totaled for the
particular reporting period.
50--------------------------------------------------------------------------------
2012 compared to 2011. OG&E's operating income increased $17.1 million, or 3.6
percent, in 2012 as compared to 2011 primarily due to a higher gross margin
partially offset by higher other operation and maintenance expense and higher
depreciation and amortization expense.
Gross Margin
Operating revenues were $2,141.2 million in 2012 as compared to $2,211.5 million
in 2011, a decrease of $70.3 million, or 3.2 percent. Cost of goods sold was
$879.1 million in 2012 as compared to $1,013.5 million in 2011, a decrease of
$134.4 million, or 13.3 percent. Gross margin was $1,262.1 million in 2012 as
compared to $1,198.0 million in 2011, an increase of $64.1 million, or 5.4
percent. The below factors contributed to the change in gross margin:
$ Change
(In millions)
Price variance (A) $ 54.1
Wholesale transmission revenue (B) 28.5
New customer growth 11.5
Non-residential demand and related revenues 4.9
Enogex transportation credit (C) 3.3
Arkansas rate increase 2.8
Oklahoma rate increase 2.7
Renewal of wholesale contract with customer 1.3
Other 0.3
Quantity variance (primarily weather) (45.3 )
Change in gross margin $ 64.1
(A) Increased due to revenues from the recovery of investments, including the
Crossroads wind farm and smart grid.
(B) Increased primarily due to the inclusion of construction work in progress in
transmission rates for specific FERC approved projects that previously
accrued allowance for funds used during construction.
(C) Increased due to a credit to OG&E's customers in 2011 related to the
settlement of OG&E's 2009 fuel adjustment clause review.
Cost of goods sold for OG&E consists of fuel used in electric generation,
purchased power and transmission related charges. Fuel expense was $642.4
million in 2012 as compared to $775.0 million in 2011, a decrease of $132.6
million, or 17.1 percent, primarily due to lower natural gas prices. OG&E's
electric generating capability is fairly evenly divided between coal and natural
gas and provides for flexibility to use either fuel to the best economic
advantage for OG&E and its customers. In 2012, OG&E's fuel mix was 52 percent
coal, 42 percent natural gas and six percent wind. In 2011, OG&E's fuel mix was
58 percent coal, 39 percent natural gas and three percent wind. Purchased power
costs were $223.0 million in 2012 as compared to $230.7 million in 2011, a
decrease of $7.7 million, or 3.3 percent, primarily due to a decrease in
cogeneration purchases and purchases in the energy imbalance service market due
to milder weather partially offset by an increase in short-term power purchases.
Transmission related charges were $13.7 million in 2012 as compared to $7.8
million in 2011, an increase of $5.9 million, or 75.6 percent, primarily due to
higher SPP charges for the base plan projects of other utilities.
Variances in the actual cost of fuel used in electric generation and certain
purchased power costs, as compared to the fuel component included in the
cost-of-service for ratemaking, are passed through to OG&E's customers through
fuel adjustment clauses. The fuel adjustment clauses are subject to periodic
review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have
authority to review the appropriateness of gas transportation charges or other
fees OG&E pays to Enogex.
51
--------------------------------------------------------------------------------Operating Expenses
Other operation and maintenance expenses were $446.3 million in 2012 as compared
to $436.0 million in 2011, an increase of $10.3 million, or 2.4 percent. The
below factors contributed to the change in other operations and maintenance
expense:
$ Change
(In millions)
Salaries and wages (A) $ 6.4Contract professional and technical services (related to smart grid)
(B)
4.2
Employee benefits (C) 3.4
Administration and assessment fees (primarily SPP and North American
Electric Reliability Corporation)
3.4
Wind farm lease expense (primarily Crossroads) (B) 3.0
Injuries and damages 1.9
Ongoing maintenance at power plants (B) 1.9
Software (primarily smart grid) (B) 1.8
Other 0.2
Temporary labor (1.7 )
Uncollectibles (2.4 )
Vegetation management (primarily system hardening) (B) (3.0 )
Allocations from holding company (primarily lower contract professional
services and lower payroll and benefits)
(3.1 )
Capitalized labor (5.7 )
Change in other operation and maintenance expense $ 10.3
(A) Increased primarily due to salary increases and an increase in incentive
compensation expense partially offset by lower headcount in 2012 and a
decrease in overtime expense.
(B) Includes costs that are being recovered through a rider.
(C) Increased primarily due to an increase in worker's compensation accruals, an
increase in medical expense and an increase in postretirement medical expense
partially offset by a decrease in pension expense.
Depreciation and amortization expense was $248.7 million in 2012 as compared to
$216.1 million in 2011, an increase of $32.6 million, or 15.1 percent, primarily
due to additional assets being placed in service throughout 2011 and 2012,
including the Crossroads wind farm, which was fully in service in January 2012,
the Sooner-Rose Hill and Sunnyside-Hugo transmission projects, which were fully
in service in April 2012, and the smart grid project which was completed in late
2012.
Additional Information
Allowance for Equity Funds Used During Construction. Allowance for equity funds
used during construction was $6.2 million in 2012 as compared to $20.4 million
in 2011, a decrease of $14.2 million, or 69.6 percent, primarily due to higher
levels of construction costs for the Crossroads wind farm in 2011.
Other Income. Other income was $8.0 million in both 2012 and 2011. Factors
affecting other income included an increased margin of $8.8 million recognized
in the guaranteed flat bill program in 2012 as a result of milder weather offset
by a decrease of $8.9 million related to the benefit associated with the tax
gross-up of allowance for equity funds used during construction.
Other Expense. Other expense was $4.3 million in 2012 as compared to $8.4
million in 2011, a decrease of $4.1 million, or 48.8 percent primarily due to a
decrease in charitable contributions.
Interest Expense. Interest expense was $124.6 million in 2012 as compared to
$111.6 million in 2011, an increase of $13.0 million, or 11.6 percent, primarily
due to a $6.9 million increase in interest expense related to lower allowance
for borrowed funds used during construction costs for the Crossroads wind farm
in 2011 and a $5.5 million increase in interest expense related to the issuance
of long-term debt in May 2011.
Income Tax Expense. Income tax expense was $94.6 million in 2012 as compared to
$117.9 million in 2011, a decrease of $23.3 million, or 19.8 percent. The
decrease in income tax expense was primarily due to an increase in the amount of
Federal renewable energy tax credits recognized associated with the Crossroads
wind farm and lower pre-tax income in 2012 as compared to 2011.
52
--------------------------------------------------------------------------------2011 compared to 2010. OG&E's operating income increased $58.6 million, or 14.2
percent, in 2011 as compared to 2010 primarily due to a higher gross margin
partially offset by higher other operation and maintenance expense.
Gross Margin
Operating revenues were $2,211.5 million in 2011 as compared to $2,109.9 million
in 2010, an increase of $101.6 million, or 4.8 percent. Cost of goods sold was
$1,013.5 million in 2011 as compared to $1,000.2 million in 2010, an increase of
$13.3 million, or 1.3 percent. Gross margin was $1,198.0 million in 2011 as
compared to $1,109.7 million in 2010, an increase of $88.3 million, or 8.0
percent. The below factors contributed to the change in gross margin:
$ Change
(In millions)
Quantity variance (primarily weather) $ 27.4
Price variance (A)
23.9
Transmission revenue (B) 15.3
New customer growth 13.1
Arkansas rate increase 6.0
Non-residential demand and related revenues 5.0
Renewal of wholesale contract with customer 3.1
Other 0.2
Enogex transportation credit (C) (5.7 )
Change in gross margin $ 88.3
(A) Increased due to revenues from the recovery of investments, including the
Windspeed transmission line, Oklahoma demand program, smart grid, system
hardening, storm recovery, the Crossroads wind farm and the OU Spirit wind
farm, and higher revenues from industrial and oilfield customers.
(B) Increased primarily due to the inclusion of construction work in progress in
transmission rates for specific FERC approved projects that previously
accrued allowance for funds used during construction.
(C) Decreased due to a credit to OG&E's customers in 2011 related to the
settlement of OG&E's 2009 fuel adjustment clause review.
Fuel expense was $775.0 million in 2011 as compared to $771.0 million in 2010,
an increase of $4.0 million, or 0.5 percent, primarily due to higher generation
primarily due to warmer weather in OG&E's service territory. OG&E's electric
generating capability is fairly evenly divided between coal and natural gas and
provides for flexibility to use either fuel to the best economic advantage for
OG&E and its customers. In 2011, OG&E's fuel mix was 58 percent coal, 39 percent
natural gas and three percent wind. In 2010, OG&E's fuel mix was 55 percent
coal, 42 percent natural gas and three percent wind. Purchased power costs were
$230.7 million in 2011 as compared to $226.5 million in 2010, an increase of
$4.2 million, or 1.9 percent, primarily due to an increase in short-term power
purchases partially offset by a decrease in purchases in the energy imbalance
service market and a decrease in cogeneration cost.
53
--------------------------------------------------------------------------------Operating Expenses
Other operation and maintenance expenses were $436.0 million in 2011 as compared
to $418.1 million in 2010, an increase of $17.9 million, or 4.3 percent. The
below factors contributed to the change in other operations and maintenance
expense:
$ Change
(In millions)
Allocations from holding company (A) $ 15.5
Salaries and wages (B) 12.1
Other marketing and sales expense (primarily demand-side management
initiatives) (C)
4.6
Uncollectible expense 3.1
Fleet transportation expense (primarily higher fuel costs in 2011)
1.6
Temporary labor expense 1.3
Administration and assessment fees (primarily SPP) 1.2
Vegetation management (primarily system hardening) (C) (2.9 )
Other (3.8 )
Injuries and damages (primarily higher reserves on claims in 2010) (5.0 )
Employee benefits (D) (9.8 )
Change in other operation and maintenance expense $ 17.9
(A) Increased primarily related to payroll and benefits expense, contract
technical and construction services and contract professional services.
(B) Increased primarily due to salary increases in 2011, increased incentive
compensation expense and increased overtime expense primarily due to storms
in April and August 2011.
(C) Includes costs that are being recovered through a rider.
(D) Decreased primarily due to a decrease in postretirement benefits expense
related to amendments to the Company's retiree medical plan adopted in
January 2011 (see Note 14 of Notes to Consolidated Financial Statements)
partially offset by a modification to OG&E's pension tracker and a decrease
in worker's compensation accruals in 2011.
Additional Information
Allowance for Equity Funds Used During Construction. Allowance for equity funds
used during construction was $20.4 million in 2011 as compared to $11.4 million
in 2010, an increase of $9.0 million, or 78.9 percent, primarily due to higher
levels of construction costs for the Crossroads wind farm in 2011.
Other Income. Other income was $8.0 million in 2011 as compared to $6.5 million
in 2010, an increase of $1.5 million, or 23.1 percent. The increase in other
income was primarily due to a benefit of $5.6 million associated with the tax
gross-up of allowance for equity funds used during construction partially offset
by increased losses of $4.2 million recognized in the guaranteed flat bill
program in 2011 from higher than expected usage resulting from warmer weather.
Other Expense. Other expense was $8.4 million in 2011 as compared to $1.6
million in 2010, an increase of $6.8 million, primarily due to an increase in
charitable contributions of $6.4 million as the holding company made the
charitable contributions in 2010.
Interest Expense. Interest expense was $111.6 million in 2011 as compared to
$103.4 million in 2010, an increase of $8.2 million, or 7.9 percent, primarily
due to a $14.0 million increase related to the issuance of long-term debt in
June 2010 and May 2011. This increase in interest expense was partially offset
by:
• a $4.9 million decrease in interest expense due to a higher
allowance for borrowed funds used during constructionprimarily due
to construction costs for the Crossroads wind farm; and
• a $1.4 million decrease in interest expense in 2011 due to interest
to customers related to the fuel over recovery balance in 2010.
Income Tax Expense. Income tax expense was $117.9 million in 2011 as compared to
$111.0 million in 2010, an increase of $6.9 million, or 6.2 percent. The
increase in income tax expense was primarily due to higher pre-tax income in
2011 as compared to 2010. This increase in income tax expense was partially
offset by:
54
--------------------------------------------------------------------------------
• the one-time, non-cash charge in 2010 for the elimination of the tax
deduction for the Medicare Part D subsidy;
• the write-off of previously recognized Oklahoma investment tax
credits in 2010 primarily due to expenditures no longereligible for
the Oklahoma investment tax credit related to the change in the tax
method of accounting for capitalization of repair expenditures; and
• higher Oklahoma investment tax credits in 2011 as compared to 2010.
Enogex (Natural Gas Midstream Operations)
Natural Gas
Transportation and Natural Gas Gathering
2012 Storage and Processing Eliminations Total
(In millions)
Operating revenues $ 639.5 $ 1,222.6 $ (253.5 ) $ 1,608.6
Cost of goods sold 504.9 868.7 (253.5 ) 1,120.1
Gross margin on revenues 134.6 353.9 - 488.5
Other operation and maintenance 49.8 123.1 - 172.9
Depreciation and amortization 24.0 84.8 - 108.8
Impairment of assets - 0.4 - 0.4
Gain on insurance proceeds - (7.5 ) - (7.5 )
Taxes other than income 15.7 12.6 - 28.3
Operating income $ 45.1 $ 140.5 $ - $ 185.6
Natural Gas
Transportation and Natural Gas Gathering
2011 Storage and Processing Eliminations Total
(In millions)
Operating revenues $ 880.1 $ 1,167.1 $ (260.1 ) $ 1,787.1
Cost of goods sold 736.0 870.7 (260.1 ) 1,346.6
Gross margin on revenues 144.1 296.4 - 440.5
Other operation and maintenance 50.7 111.8 - 162.5
Depreciation and amortization 22.0 55.6 - 77.6
Impairment of assets - 6.3 - 6.3
Gain on insurance proceeds - (3.0 ) - (3.0 )
Taxes other than income 15.0 7.0 0.1 22.1
Operating income $ 56.4 $ 118.7 $ (0.1 ) $ 175.0
Natural Gas Natural Gas
Transportation and Gathering and
2010 Storage Processing Eliminations Total
(In millions)
Operating revenues $ 984.8 $ 1,005.6 $ (282.7 ) $ 1,707.7
Cost of goods sold 834.5 733.3 (282.7 ) 1,285.1
Gross margin on revenues 150.3 272.3 - 422.6
Other operation and maintenance 53.8 91.5 - 145.3
Depreciation and amortization 21.2 50.1 - 71.3
Impairment of assets 0.7 0.4 - 1.1
Taxes other than income 14.2 6.4 - 20.6
Operating income $ 60.4 $ 123.9 $ - $ 184.3
55--------------------------------------------------------------------------------
Operating Data
Year ended December 31 2012 2011 2010
Gathered volumes - TBtu/d 1.41 1.36 1.32
Incremental transportation volumes - TBtu/d (A) 0.67 0.58 0.40
Total throughput volumes - TBtu/d
2.08 1.94 1.72
Natural gas processed - TBtu/d 0.98 0.79 0.82
Condensate sold - million gallons 35 27 24
Average condensate sales price per gallon $ 1.95 $ 2.09 $ 1.81
NGLs sold (keep-whole) - million gallons
162 167 187
NGLs sold (purchased for resale) - million gallons 667 487 470
NGLs sold (percent-of-liquids) - million gallons 24 25 26
NGLs sold (percent-of-proceeds) - million gallons 14 6 5
Total NGLs sold - million gallons
867 685 688
Average NGLs sales price per gallon $ 0.89 $ 1.16 $ 0.96
Average natural gas sales price per MMBtu $ 2.79 $ 4.08 $ 4.24
(A) Incremental transportation volumes consist of natural gas moved only on the
transportation pipeline.
2012 compared to 2011. Enogex's operating income increased $10.6 million, or 6.1
percent, in 2012 as compared to 2011. This increase was primarily due to a
higher gross margin, a higher gain on insurance proceeds related to the
reimbursement of costs incurred to replace the damaged train at the Cox City
natural gas processing plant discussed below and lower impairment of assets
partially offset by higher other operation and maintenance expense, higher
depreciation and amortization expense and higher taxes other than income. The
higher gross margin related to (i) increased gathering rates and volumes
associated with ongoing expansion projects and increased volumes from gas
gathering assets acquired in November 2011 and August 2012 and (ii) increased
inlet volumes resulting from the return to full service of the Cox City natural
gas processing plant in September 2011, the South Canadian natural gas
processing plant, which was placed in service in December 2011, and the Wheeler
natural gas processing plant, which was placed in service in August 2012. These
increases in gross margin were partially offset by lower average natural gas and
NGLs prices. In 2012, imbalance volume changes and realized margin on physical
gas long/short positions decreased the gross margin by $7.5 million, net of
corresponding imbalance and fuel tracker balances and the impact of the recovery
of prior years' under-recovered fuel positions during 2012.
Other operation and maintenance expense increased $10.4 million, or 6.4 percent,
primarily due to:
• increased payroll and benefits costs due to increased headcount to
support business growth; and
• increased rental expense on compression due to leases acquired in
the August 2012 gas gathering acquisition partially offset by the
reduction of rental payments on the Atoka plant, which was taken out
of service in August 2011.
These increases in other operation and maintenance expense were partially offset
by:
• decreased costs for soil remediation projects; and
• lower contract technical and professional services expense and
materials and supplies expense due to a decrease in non-capital
projects during 2012.
Depreciation and amortization expense increased $31.2 million, or 40.2 percent,
primarily due to additional assets placed in service throughout 2011 and 2012,
including the gas gathering assets acquired in November 2011 and August 2012.
Impairment of assets decreased $5.9 million, or 93.7 percent, primarily due to
an impairment of $5.0 million related to a management decision in August 2011 to
use third-party processing exclusively for gathered volumes dedicated to the
Atoka processing plant and, therefore, to take the processing plant out of
service and return it to the lessor in accordance with the rental agreement. The
noncontrolling interest portion of the impairment was $2.5 million which was
included in Net Income Attributable to Noncontrolling Interests in the Company's
Consolidated Statement of Income.
Gain on insurance proceeds increased $4.5 million related to the reimbursement
of costs incurred to replace the damaged train at the Cox City natural gas
processing plant.
56
--------------------------------------------------------------------------------
Taxes other than income increased $6.2 million, or 28.1 percent, primarily due
to:
• sales tax of $3.5 million related to the acquisition of certain gas gathering assets in September 2012 as discussed in Note 3 of Notes
to Consolidated Financial Statements; and
• increased ad valorem taxes resulting from additional assets placed
in service throughout 2011 and 2012.
Natural Gas Transportation and Storage
The natural gas transportation and storage business contributed $134.6 million
of Enogex's consolidated gross margin during 2012 as compared to $144.1 million
during 2011, a decrease of $9.5 million or 6.6 percent. The transportation
operations contributed $110.1 million of Enogex's consolidated gross margin
during 2012 as compared to $118.8 million during 2011. The storage operations
contributed $24.5 million of Enogex's consolidated gross margin during 2012 as
compared to $25.3 million during 2011. Gross margin decreased primarily due to:
• lower volumes and realized margin on sales of physical natural gas
long positions associated with transportation operations, which
decreased the gross margin by $6.4 million, net of imbalances and
fuel tracker balances;
• lower storage fees due to terminated contracts andrenegotiated
contracts with less favorable terms, which decreased the gross
margin by $2.5 million;
• lower gains on storage sales during 2012, which decreased the gross
margin by $1.9 million;
• lower crosshaul revenues in 2012 resulting from the reversal of a
previously recognized reserve of $3.0 million associated with the
settlement of Enogex's 2009 FERC Section 311 rate case during 2011
partially offset by increased utilization of $1.3 million during
2012, which decreased the gross margin by $1.7 million; and
• lower transportation fees due to unbundling oftransportation and
gathering fees as contracts are renegotiated, which decreased the
gross margin by $1.4 million.
These decreases in the natural gas transportation and storage gross margin were
partially offset by:
• higher realized margin on hedging activity associated with natural
gas storage inventory from storage, which increased the gross margin
by $4.4 million; and
• higher transportation demand fees as a result of new contracts,
which increased the gross margin by $2.3 million.
Other operation and maintenance expense for the natural gas transportation and
storage business was $0.9 million, or 1.8 percent, lower during 2012 as compared
to 2011 primarily due to lower contract technical and professional services
expense and materials and supplies expense due to a decrease in non-capital
projects during 2012 partially offset by increased payroll and benefits costs
due to increased headcount to support business growth.
Natural Gas Gathering and Processing
The natural gas gathering and processing business contributed $353.9 million of
Enogex's consolidated gross margin during 2012 as compared to $296.4 million
during 2011, an increase of $57.5 million, or 19.4 percent. The gathering
operations contributed $145.9 million of Enogex's consolidated gross margin
during 2012 as compared to $125.2 million during 2011. The processing operations
contributed $208.0 million of Enogex's consolidated gross margin during 2012 as
compared to $171.2 million during 2011.
During 2012, Enogex realized a higher gross margin in its natural gas gathering
and processing operations related to (i) increased gathering rates and volumes
associated with ongoing expansion projects, primarily in the Granite Wash play,
which has added richer natural gas to Enogex's system, and increased volumes
from gas gathering assets acquired in November 2011 and August 2012, (ii)
increased inlet volumes resulting from the return to full service of the Cox
City natural gas processing plant in September 2011, the South Canadian natural
gas processing plant, which was placed in service in December 2011, and the
Wheeler natural gas processing plant, which was placed in service in August
2012, and (iii) contract conversion of one of Enogex's five largest customer's
Oklahoma production volumes to fixed fee effective July 1, 2011. These increases
in the gathering and processing gross margin were partially offset by lower
average natural gas and NGLs prices.
The above factors contributed to the increase in the natural gas gathering and
processing gross margin as follows:
• an increased gross margin on keep-whole processing of $28.4 million;
• an increase in gathering fees associated with ongoing expansion
projects and increased volumes from gas gathering assets, which
increased the gross margin by $16.8 million;
57--------------------------------------------------------------------------------
• an increase in condensate revenues associated with higher condensate
margins and volumes, which increased the gross margin by $14.2
million; and
• an increased gross margin on fixed-fee contracts of $8.4 million.
These increases in the natural gas gathering and processing gross margin were
partially offset by:
• an increase in the utilization of third-party processing as a result
of (i) the Atoka processing plant being taken out of service in
August 2011 and (ii) increased activity from western Oklahoma and
Texas Panhandle expansion projects currently processed by third
parties, which together decreased the gross margin by $6.2 million;
• a decrease in percent-of-liquids and percent-of-proceeds margins of
$4.4 million; and
• lower volumes and realized margin on sales of physical natural gas
long positions associated with gathering operations, which decreased
the gross margin by $1.1 million, net of imbalances and fuel tracker
obligations.
Other operation and maintenance expense for the natural gas gathering and
processing business was $11.3 million, or 10.1 percent, higher during 2012 as
compared to 2011 primarily due to:
• increased payroll and benefits costs due to increased headcount to
support business growth; and
• increased rental expense on compression due to leases acquired in
the August 2012 gas gathering acquisition partially offset by the
reduction of rental payments on the Atoka plant, which was taken out
of service in August 2011.
These increases in other operation and maintenance expense were partially offset
by decreased costs for soil remediation projects.
Enogex Consolidated Information
Other Income. Enogex's consolidated other income was $1.0 million during 2012 as
compared to $3.9 million during 2011, a decrease of $2.9 million, or 74.4
percent, due to the recognition in April 2011 of a gain related to the sale of
the Harrah processing plant and the associated Wellston and Davenport gathering
assets.
Other Expense. Enogex's consolidated other expense was $4.5 million during 2012
as compared to $1.3 million during 2011, an increase of $3.2 million due to
higher non-cash losses on retirements of equipment during 2012.
Interest Expense. Enogex's consolidated interest expense was $32.6 million
during 2012 as compared to $22.9 million during 2011, an increase of $9.7
million, or 42.4 percent, primarily due to:
• a decrease in capitalized interest during 2012 due to the completion
of several large capital projects as compared to 2011;
• higher borrowings partially offset by repayments under Enogex's
revolving credit agreement during 2012 as compared to 2011; and
• borrowings under Enogex's term loan during 2012 with nocomparable
item during 2011.
Income Tax Expense. Enogex's consolidated income tax expense was $45.7 million
during 2012 as compared to $51.7 million during 2011, a decrease of $6.0
million, or 11.6 percent, primarily due to lower pre-tax income (net of
noncontrolling interest) during 2012 as compared to 2011.
Noncontrolling Interest. Enogex's net income attributable to noncontrolling
interest was $29.7 million during 2012 as compared to $20.8 million during 2011,
an increase of $8.9 million or 42.8 percent, due to higher net income, the
ArcLight group's increased ownership in Enogex Holdings as a result of the
ArcLight group funding capital contributions at a disproportionate percentage to
OGE Holdings throughout 2011 and an impairment recorded in August 2011 related
to the Atoka processing plant.
Non-Recurring Items. During 2012, Enogex had an increase in net income of $4.6
million due to a gain on insurance proceeds related to the reimbursement of
costs incurred to replace the damaged train at the Cox City natural gas
processing plant partially offset by a decrease in net income of $2.1 million
related to sales taxes on the assets acquired in the gas gathering acquisitions
in August 2012, as discussed in Note 3 of Notes to Consolidated Financial
Statements, which Enogex does not consider to be reflective of its ongoing
performance. During 2011, Enogex had an increase in net income of $2.3 million
relating to the sale of the Harrah processing plant and the associated Wellston
and Davenport gathering assets in April 2011, which Enogex does not consider to
be reflective of its ongoing performance.
58
--------------------------------------------------------------------------------
2011 compared to 2010. Enogex's operating income decreased $9.3 million, or 5.0
percent, in 2011 as compared to 2010. This decrease was primarily due to higher
other operation and maintenance expense, higher depreciation and amortization
expense, lower average natural gas prices and a slight decrease in inlet
processing volumes related to the 120 MMcf/d Cox City natural gas processing
plant being out of service due to the fire from December 2010 until September
2011 and the sale of the Harrah processing plant and the associated Wellston and
Davenport gathering assets in April 2011. These decreases were partially offset
by higher NGLs prices and increased gathered volumes associated with ongoing
expansion projects. In 2011, imbalance volume changes and realized margin on
physical gas long/short positions decreased the gross margin by $14.8 million,
net of corresponding imbalance and fuel tracker balances and the impact of the
recovery of prior years' under-recovered fuel positions during 2010.
Other operation and maintenance expense increased $17.2 million, or 11.8
percent, primarily due to:
• increased payroll and benefits costs due to increased headcount to
support business growth;
• increased contract technical and professional services expense and
materials and supplies expense due to an increase in non-capital
projects in 2011;
• increased property insurance costs;
• increased rental expense due to growing demand for compression as
Enogex's business expands; and
• increased costs due to soil remediation projects.
Depreciation and amortization expense increased $6.3 million, or 8.8 percent,
primarily due to additional assets placed in service throughout 2010 and 2011.
Impairment of assets increased $5.2 million in 2011 primarily due to an
impairment of $5.0 million related to a management decision in August 2011 to
use third-party processing exclusively for gathered volumes dedicated to the
Atoka processing plant and, therefore, to take the processing plant out of
service and return it to the lessor in accordance with the rental agreement. The
noncontrolling interest portion of the impairment was $2.5 million which was
included in Net Income Attributable to Noncontrolling Interests in the Company's
Consolidated Statement of Income.
Gain on insurance proceeds was $3.0 million in 2011 with no comparable item in
2010. The gain on insurance proceeds was for reimbursement related to the
damaged train at the Cox City natural gas processing plant being replaced and
the facility being returned to full service in September 2011.
Natural Gas Transportation and Storage
The natural gas transportation and storage business contributed $144.1 million
of Enogex's gross margin in 2011 as compared to $150.3 million in 2010, a
decrease of $6.2 million, or 4.1 percent. The transportation operations
contributed $118.8 million of Enogex's consolidated gross margin in 2011 as
compared to $116.9 million in 2010. The storage operations contributed $25.3
million of Enogex's consolidated gross margin in 2011 as compared to $33.4
million in 2010. Gross margin decreased primarily due to:
• lower volumes and realized margin on sales of physical natural gas
long positions associated with transportation operations in 2011.
Gross margin in 2011 included the under recovery of fuel positions
as compared to 2010 that included the recovery of prior year's
under-recovered fuel positions, which reduced the gross margin in
2011 by $12.1 million, net of imbalance and fuel tracker
obligations;
• lower of cost or market adjustments on the natural gas storage
inventory reflective of higher inventory volumes in 2011, which
decreased the gross margin by $4.4 million; and
• lower realized margin on sale of natural gas inventory from storage
due to a reduction in the realized natural gas market spreads, which
decreased the gross margin by $2.8 million.
These decreases in the natural gas transportation and storage gross margin were
partially offset by:
• higher capacity lease services under the MEP and Gulf Crossing
capacity leases in 2011 as a result of pipeline integrity work on an
Enogex pipeline in 2010, which increased the gross margin by $7.1
million;
• higher firm 311 services due to new contracts with more favorable
rates in 2011, which increased the gross margin by $5.4 million;
• more favorable results from Enogex's customer-focused risk
management services, natural gas marketing activities and trading
activities and the expiration of an unfavorable transportation
contract, which increased the gross margin by $2.2 million;
59--------------------------------------------------------------------------------
• higher interruptible transportation fees due to new contracts with
more favorable rates in 2011, which increased the gross margin by
$1.6 million; and
• higher crosshaul revenues in 2011 resulting from thereversal of a
previously recognized reserve of $3.0 million associated with the
settlement of Enogex's 2009 FERC Section 311 rate case partially
offset by decreased utilization of $2.5 million in 2011 due to
shippers utilizing crosshaul service in 2010 as a result of pipeline
integrity work, which increased the 2011 gross margin by $0.5
million.
Other operation and maintenance expense for the natural gas transportation and
storage business was $3.1 million, or 5.8 percent, lower in 2011 as compared to
2010 primarily due to decreased contract technical and professional services
expense and materials and supplies expense due to a decrease in non-capital
projects in 2011 partially offset by an increase in payroll and benefits costs
due to increased headcount to support business growth.
Natural Gas Gathering and Processing
The natural gas gathering and processing business contributed $296.4 million of
Enogex's consolidated gross margin in 2011 as compared to $272.3 million in
2010, an increase of $24.1 million, or 8.9 percent. The gathering operations
contributed $125.2 million of Enogex's consolidated gross margin in 2011 as
compared to $117.6 million in 2010. The processing operations contributed $171.2
million of Enogex's consolidated gross margin in 2011 as compared to $154.7
million in 2010.
In 2011, Enogex realized a higher gross margin in its natural gas gathering and
processing operations primarily as the result of continued growth in gathered
volumes from ongoing expansion projects, primarily in the Granite Wash play and
Cana/Woodford Shale play, which has added richer natural gas to Enogex's system
and higher NGLs prices. Although gathered volumes increased over 2010, gathering
and processing volumes grew at a slower pace during the fourth quarter of 2011
than Enogex had anticipated. The increased gathering volumes were partially
offset by the contract conversion of one of Enogex's five largest customer's
Oklahoma production volumes to fixed fee effective July 1, 2011, a slight
decrease in inlet processing volumes related to the 120 MMcf/d Cox City natural
gas processing plant being out of service due to the fire from December 2010
until September 2011, the sale of the Harrah processing plant and the associated
Wellston and Davenport gathering assets in April 2011 and lower average natural
gas prices.
The above factors contributed to the increase in the natural gas gathering and
processing gross margin as follows:
• an increase in condensate revenues associated with higher condensate
prices and volumes, which increased the gross margin by $11.1
million;
• an increase in gathering fees associated with ongoing expansion
projects, which increased the gross margin by $10.7 million;
• an increased gross margin on keep-whole processing of $4.8 million;
• an increased gross margin on percent-of-liquids and
percent-of-proceeds contracts of $2.6 million; and
• an increased gross margin on fixed-fee contract of $1.3 million.
These increases in the natural gas gathering and processing gross margin were
partially offset by:
• an increase in the utilization of third-party processing as a result
of the reduced capacity related to the Cox City processing plant
being out of service until September 2011 and the Atoka processing
plant being taken out of service in August 2011, whichdecreased the
gross margin by $3.4 million; and
• lower volumes and realized margin on sales of physical natural gas
long positions associated with gathering operations, which decreased
the gross margin in 2011 by $2.7 million, net of imbalance and fuel
tracker obligations.
Other operation and maintenance expense for the natural gas gathering and
processing business was $20.3 million, or 22.2 percent, higher in 2011 as
compared to 2010 primarily due to:
• increased payroll and benefits costs due to increased headcount to
support business growth;
• increased contract technical and professional services expense and
materials and supplies expense due to an increase in non-capital
projects in 2011;
• increased rental expense due to growing demand for compression as
Enogex's business expands; and
• increased costs due to soil remediation projects.
60
-------------------------------------------------------------------------------- Enogex Consolidated Information
Other Income. Enogex's consolidated other income was $3.9 million in 2011 as
compared to $0.2 million in 2010, an increase of $3.7 million, primarily due to
the recognition of a gain related to the sale of the Harrah processing plant and
the associated Wellston and Davenport gathering assets in April 2011.
Interest Expense. Enogex's consolidated interest expense was $22.9 million in
2011 as compared to $30.4 million in 2010, a decrease of $7.5 million, or 24.7
percent, primarily due to:
• an increase of $6.1 million in capitalized interest related to
increased construction activity in 2011; and
• a decrease of $1.0 million in interest expense in 2011 due to the
retirement of long-term debt in January 2010.
Income Tax Expense. Enogex's consolidated income tax expense was $51.7 million
in 2011 as compared to $57.7 million in 2010, a decrease of $6.0 million, or
10.4 percent, primarily due to:
• lower pre-tax income in 2011 as compared to 2010; and
• the one-time, non-cash charge in 2010 for the elimination of the tax
deduction for the Medicare Part D subsidy.
Noncontrolling Interest. Enogex's net income attributable to noncontrolling
interest was $20.8 million in 2011 as compared to $5.1 million in 2010, an
increase of $15.7 million, due to the equity sale of a membership interest in
Enogex Holdings to the ArcLight group partially offset by an impairment recorded
in August 2011 related to the Atoka processing plant.
Non-Recurring Item. During 2011, Enogex had an increase in net income of $2.3
million relating to the sale of the Harrah processing plant and the associated
Wellston and Davenport gathering assets in April 2011, which Enogex does not
consider to be reflective of its ongoing performance.
Timing Item. Enogex's net income in 2011 was $82.2 million, which included a
loss of $2.6 million resulting from recording Enogex's natural gas storage
inventory at the lower of cost or market value. The offsetting gains from the
sale of withdrawals from inventory were realized during the first quarter of
2012.
Non-GAAP Financial Measure
Enogex has included in this Form 10-K the non-GAAP financial measure EBITDA.
EBITDA is a supplemental non-GAAP financial measure used by external users of
the Company's financial statements such as investors, commercial banks and
others, to assess:
• the financial performance of Enogex's assets without regard to
financing methods, capital structure or historical cost basis;
• Enogex's operating performance and return on capital ascompared to
other companies in the midstream energy sector, without regard to
financing or capital structure; and
• the viability of acquisitions and capital expenditureprojects and
the overall rates of return on alternative investmentopportunities.
Enogex provides a reconciliation of EBITDA to net income attributable to Enogex
Holdings, which Enogex considers to be its most directly comparable financial
measure as calculated and presented in accordance with GAAP. The non-GAAP
financial measure of EBITDA should not be considered as an alternative to GAAP
net income attributable to Enogex Holdings. EBITDA is not a presentation made in
accordance with GAAP and has important limitations as an analytical tool. EBITDA
should not be considered in isolation or as a substitute for analysis of
Enogex's results as reported under GAAP. Because EBITDA excludes some, but not
all, items that affect net income and is defined differently by different
companies in Enogex's industry, Enogex's definition of EBITDA may not be
comparable to a similarly titled measure of other companies.
To compensate for the limitations of EBITDA as an analytical tool, Enogex
believes it is important to review the comparable GAAP measure and understand
the differences between the measures.
61
--------------------------------------------------------------------------------Reconciliation of EBITDA to net income attributable to Enogex Holdings
(In millions)
2012 2011 2010
Net income attributable to Enogex Holdings $ 147.8 $ 155.9 $ 476.1
Add:
Interest expense, net
32.6 22.9 30.3
Income tax expense (A) 0.2 0.2 (325.0 )
Depreciation and amortization expense (B) 111.6 77.2 70.2
EBITDA
$ 292.2 $ 256.2 $ 251.6
OGE Energy's portion $ 236.6 $ 222.9 $ 248.8
(A) As of November 1, 2010, Enogex Holdings' earnings are no longer subject to
tax (other than Texas state margin taxes) and are taxable at the individual
partner level.
(B) Includes amortization of certain customer-based intangible assets associated
with the acquisition from Cordillera in November 2011, which is included in
gross margin for financial reporting purposes.
Off-Balance Sheet Arrangement
OG&E Railcar Lease Agreement
OG&E has a noncancellable operating lease with purchase options, covering 1,389
coal hopper railcars to transport coal from Wyoming to OG&E's coal-fired
generation units. Rental payments are charged to Fuel Expense and are recovered
through OG&E's tariffs and fuel adjustment clauses. On December 15, 2010, OG&E
renewed the lease agreement effective February 1, 2011. At the end of the new
lease term, which is February 1, 2016, OG&E has the option to either purchase
the railcars at a stipulated fair market value or renew the lease. If OG&E
chooses not to purchase the railcars or renew the lease agreement and the actual
fair value of the railcars is less than the stipulated fair market value, OG&E
would be responsible for the difference in those values up to a maximum of $22.8
million.
On January 11, 2012, OG&E executed a five-year lease agreement for 135 railcars
to replace railcars that have been taken out of service or destroyed. OG&E is
also required to maintain all of the railcars it has under lease to transport
coal from Wyoming and has entered into agreements with Progress Rail Services
and WATCO, both of which are non-affiliated companies, to furnish this
maintenance.
OG&E is also required to maintain all of the railcars it has under lease to
transport coal from Wyoming and has entered into agreements with Progress Rail
Services and WATCO, both of which are non-affiliated companies, to furnish this
maintenance.
Liquidity and Capital Resources
Working Capital
Working capital is defined as the amount by which current assets exceed current
liabilities. The Company's working capital requirements are driven generally by
changes in accounts receivable, accounts payable, commodity prices, credit
extended to, and the timing of collections from, customers, the level and timing
of spending for maintenance and expansion activity, inventory levels and fuel
recoveries.
The balance of Accounts Receivable, Net and Accrued Unbilled Revenues was $352.7
million and $381.8 million at December 31, 2012 and 2011, respectively, a
decrease of $29.1 million, or 7.6 percent, primarily due to a decrease in
billings to OG&E's customers in 2012 due to milder weather in 2012, a decrease
at Enogex due to lower natural gas sales volumes and prices and the timing of
customer payments received partially offset by higher transmission revenue and
increased rates at OG&E.
The balance of Accounts Payable was $396.7 million and $388.0 million at
December 31, 2012 and 2011, respectively, an increase of $8.7 million, or 2.2
percent, primarily due to increased NGLs volumes at Enogex partially offset by
lower NGLs prices at Enogex, a decrease in accruals and the timing of ad valorem
payments.
62--------------------------------------------------------------------------------Cash Flows
2012 vs. 2011 2011 vs. 2010
Year ended December 31 (In millions) 2012 2011 2010 $ Change % Change $ Change % Change
Net cash provided from operating $ 1,046.1 $ 833.9 $ 782.5 $
212.2 25.4 % $ 51.4 6.6 %
activities
Net cash used in investing (1,192.6 ) (1,395.8 ) (846.1 ) 203.2 (14.6 )% (549.7 ) 65.0 %
activities
Net cash provided from financing 143.7 564.2 7.8 (420.5 ) (74.5 )% 556.4 *
activities
* Percentage is greater than 100 percent.
Operating Activities
The increase of $212.2 million, or 25.4 percent, in net cash provided from
operating activities in 2012 as compared to 2011 was primarily due to:
• higher fuel recoveries at OG&E in 2012 as compared to 2011;
• an increase in cash received in 2012 from transmission revenue and
the recovery of investments including the Crossroads wind farm and
smart grid partially offset by milder weather in 2012; and
• an increase in gathered volumes and NGLs volumes at Enogex during
2012 as compared to 2011 partially offset by lower natural gas and
NGLs prices in 2012 as compared to 2011.
The increase of $51.4 million, or 6.6 percent, in net cash provided from
operating activities in 2011 as compared to 2010 was primarily due to:
• lower fuel refunds at OG&E in 2011 as compared to 2010; and
• cash received in 2011 from an increase in billings to OG&E's
customers due to warmer weather in OG&E's service territory in 2011;
These increases in net cash provided from operating activities was partially
offset by income tax refunds received in 2010 related to a carry back of the
2008 tax loss resulting from a change in tax method of accounting for
capitalization of repair expenditures and accelerated tax bonus depreciation.
Investing Activities
The decrease of $203.2 million, or 14.6 percent, in net cash used in investing
activities in 2012 as compared to 2011 was primarily due to lower levels of
capital expenditures in 2012 related to the Crossroads wind farm at OG&E and
lower levels of capital expenditures related to gathering and processing
expansion projects at Enogex.
The increase of $549.7 million, or 65.0 percent, in net cash used in investing
activities in 2011 as compared to 2010 primarily related to higher levels of
capital expenditures in 2011 related to various transmission projects and the
Crossroads wind farm at OG&E and gathering and processing expansion projects at
Enogex.
Financing Activities
The decrease of $420.5 million, or 74.5 percent, in net cash provided from
financing activities in 2012 as compared to 2011 was primarily due to:
• lower contributions from the ArcLight group during 2012 as compared to 2011;
• higher borrowings under Enogex's revolving credit agreement during 2011; and
• repayments of Enogex's line of credit during 2012.
These decreases in net cash provided from financing activities were partially
offset by an increase in short-term debt borrowings during 2012 as compared to
2011.
The increase of $556.4 million in net cash provided from financing activities in
2011 as compared to 2010 was primarily due to:
• repayment in 2010 of the remaining balance of Enogex LLC's $400
million 8.125% senior notes which matured on January 15, 2010;
63--------------------------------------------------------------------------------• an increase in short-term debt borrowings in 2011 as compared to 2010;
• contributions from the noncontrolling interest partners in 2011;
• higher borrowings under Enogex LLC's revolving credit agreement in 2011; and
• a decrease in repayments of borrowings under Enogex LLC's revolving
credit agreement in 2011 as compared to 2010.
Future Capital Requirements and Financing Activities
The Company's primary needs for capital are related to acquiring or constructing
new facilities and replacing or expanding existing facilities at OG&E and
Enogex. Other working capital requirements are expected to be primarily related
to maturing debt, operating lease obligations, hedging activities, fuel clause
under and over recoveries and other general corporate purposes. The Company
generally meets its cash needs through a combination of cash generated from
operations, short-term borrowings (through a combination of bank borrowings and
commercial paper) and permanent financings.
Capital Expenditures
The Company's consolidated estimates of capital expenditures for the years 2013
through 2017 are shown in the following table. These capital expenditures
represent the base maintenance capital expenditures (i.e., capital expenditures
to maintain and operate the Company's businesses) plus capital expenditures for
known and committed projects.
(In millions) 2013 2014 2015 2016 2017
OG&E Base Transmission $ 65 $ 50 $ 50 $ 50 $ 50
OG&E Base Distribution 175 175 175 175 175
OG&E Base Generation 80 75 75 75 75
OG&E Other 15 15 15 15 15
Total OG&E Base Transmission, Distribution,
Generation and Other 335 315 315 315 315
OG&E Known and Committed Projects:
Transmission Projects:
Balanced Portfolio 3E Projects (A) 205 25 - - -
SPP Priority Projects (B) 165 110 - - -
SPP Integrated Transmission Projects (C) 5 5 - 40 40
Total Transmission Projects 375 140 - 40 40
Other Projects:
Smart Grid Program 25 25 10 10 -
System Hardening 15 - - - -
Environmental - low NOX burners 30 20 25 20 -
Total Other Projects 70 45 35 30 -
Total OG&E Known and Committed Projects 445 185 35 70 40
Total OG&E (D) 780 500 350 385 355
Enogex LLC Base Maintenance 50 55 55 55 55
Enogex LLC Known and Committed Projects:
Western Oklahoma / Texas Panhandle Gathering
Expansion 380 180 140 80 65
Other Gathering Expansion 25 15 10 10 10
Total Enogex LLC Known and Committed Projects 405 195 150 90 75
Total Enogex LLC (E) 455 250 205 145 130
OGE Energy 10 10 10 10 10
Total capital expenditures $ 1,245 $ 760 $ 565 $ 540 $ 495
(A) Balanced Portfolio 3E includes three projects to be built by OG&E and
includes: (i) construction of 135 miles of transmission line from OG&E's
Seminole substation in a northeastern direction to OG&E's Muskogee substation
at an estimated cost of $175 million for OG&E, which is expected to be in
service by late 2013, (ii) construction of 96 miles of transmission line from
OG&E's Woodward District Extra High Voltage substation in a southwestern
direction to the Oklahoma/Texas Stateline to a companion transmission line to
be built by Southwestern Public Service to its Tuco substation at an
estimated cost of
64--------------------------------------------------------------------------------
$115 million for OG&E, which is expected to be in service by mid-2014 and (iii)
construction of 39 miles of transmission line from OG&E's Sooner substation in
an eastern direction to the Grand River Dam Authority Cleveland substation at an
estimated cost of $45 million for OG&E, which was placed in service in February
2013.
(B) The Priority Projects consist of several transmission projects, two of which
have been assigned to OG&E. The 345 kilovolt projects include: (i)
construction of 99 miles of transmission line from OG&E's Woodward District
Extra High Voltage substation to a companion transmission line to be built by
Southwestern Public Service to its Hitchland substation in the Texas
Panhandle at an estimated cost of $185 million for OG&E, which is expected to
be in service by mid-2014 and (ii) construction of 77 miles of transmission
line from OG&E's Woodward District Extra High Voltage substation to a
companion transmission line at the Kansas border to be built by either
Mid-Kansas Electric Company or another company assigned by Mid-Kansas
Electric Company at an estimated cost of $150 million to OG&E, which is
expected to be in service by late 2014. OG&E began construction on the Hitchland project in November 2012 and expects to begin construction on the
Kansas project in June 2013.
(C) On January 31, 2012, the SPP approved the Integrated Transmission Plan Near
Term and Integrated Transmission Plan 10-year projects. These plans include
two projects to be built by OG&E: (i) construction of 47 miles of
transmission line from OG&E's Gracemont substation in a northwestern
direction to a companion transmission line to be built by American Electric
Power to its Elk City substation at an estimated cost of $75 million for
OG&E, which is expected to be in service by early 2018, and (ii) construction
of 126 miles of transmission line from OG&E's Woodward District Extra High
Voltage substation in a southeastern direction to OG&E's Cimarron substation
and construction of a new substation on this transmission line, the Mathewson
substation, at an estimated cost of $210 million for OG&E, which is expected
to be in service by early 2021. On April 9, 2012, OG&E received a notice to
construct these projects from the SPP. On June 26, 2012, OG&E responded to
the SPP that OG&E will construct the projects discussed above and is moving
forward with more detailed cost estimates that must be reviewed and approved
by the SPP. OG&E and American Electric Power are currently in discussions
regarding how much of the 94 mile Elk City to Gracemont transmission line
will be built by OG&E and American Electric Power. American Electric Power
has argued for a larger portion of such transmission line than the
traditional 50 percent split. The capital expenditures related to these
projects are presented in the summary of capital expenditures for known and
committed projects above.
(D) The capital expenditures above exclude any environmental expenditures
associated with:
• Pollution control equipment related to controlling SO2 emissions under the
regional haze requirements due to the uncertainty regarding the approach
and timing for such pollution control equipment. The SO2 emissions
standards in the EPA's FIP could require the installation of Dry Scrubbers
or fuel switching. OG&E estimates that installing such Dry Scrubbers could
cost more than $1.0 billion. The FIP is being challenged by OG&E and the
state of Oklahoma. On June 22, 2012, OG&E was granted a stay of the FIP by
the U.S. Court of Appeals for the Tenth Circuit, which delays the timing
of required implementation of the SO2 emissions standards in the rule. The
merits of the appeal have been fully briefed, and oral argument is
scheduled to occur on March 6, 2013. Neither the outcome of the challenge
to the FIP nor the timing of any required capital expenditures can be
predicted with any certainty at this time, but such capital expenditures
could be significant.
• Installation of control equipment for compliance with MATS by a deadline
of April 16, 2015, with the possibility of a one-year extension. OG&E is
currently planning to utilize activated carbon injection and low levels of
dry sorbent injection at each of its five coal-fired units. Due to various
uncertainties about the final design, the potential use of this technology
relating to regional haze measures and the specifications for the control
equipment, the resulting cost estimates currently range from $34 million
to $72 million per unit.
OG&E is currently evaluating options to comply with environmental requirements.
For further information, see "Environmental Laws and Regulations" below.
(E) These capital expenditures represent 100 percent of Enogex LLC's capital
expenditures, of which a portion may be funded by the ArcLight group. Until
the ArcLight group owns 50 percent of the equity of Enogex Holdings, the
ArcLight group will fund capital contributions in an amount higher than its
proportionate interest. If necessary, the ArcLight group will fund between 50
percent and 90 percent of required capital contributions during that
period. The remainder of the required capital contributions (i.e., between 10
percent and 50 percent) will be funded by OGE Holdings.
Additional capital expenditures beyond those identified in the table above,
including additional incremental growth opportunities in electric transmission
assets and at Enogex LLC, will be evaluated based upon their impact upon
achieving the Company's financial objectives. The capital expenditure
projections related to Enogex LLC in the table above reflect base market
conditions at February 27, 2013 and do not reflect the potential opportunity for
a set of growth projects that could materialize. Also, if drilling activity
declines in the future, this could reduce Enogex's capital expenditures in the
table above.
65
--------------------------------------------------------------------------------Contractual Obligations
The following table summarizes the Company's contractual obligations at
December 31, 2012. See the Company's Consolidated Statements of Capitalization
and Note 16 of Notes to Consolidated Financial Statements for additional
information.
(In millions) 2013 2014-2015 2016-2017 After 2017 Total
Maturities of long-term debt (A) $ 0.2 $ 550.4 $ 235.4 $ 2,070.1 $ 2,856.1
Operating lease obligations
OG&E railcars 3.2 5.5 27.3 - 36.0
OG&E wind farm land leases 2.0 4.2 4.5 51.2 61.9
OGE Energy noncancellable operating lease 0.3 1.6 1.6 0.7 4.2
Enogex noncancellable operating leases 5.2 7.2 4.1 - 16.5
Total operating lease obligations 10.7 18.5 37.5 51.9 118.6
Other purchase obligations and commitments
OG&E cogeneration capacity and fixed
operation and maintenance payments 87.9 170.3 162.5 315.3 736.0
OG&E expected cogeneration energy payments 58.6 134.3 168.3 468.7 829.9
OG&E minimum fuel purchase commitments 405.0 519.8 - - 924.8
OG&E expected wind purchase commitments 57.5 116.9 120.6 838.0 1,133.0
OG&E long-term service agreement
8.0 34.5 12.6 53.0 108.1
commitments
EER commitments 11.9 15.5 0.8 - 28.2
Total other purchase obligations and 628.9 991.3 464.8 1,675.0 3,760.0
commitments
Total contractual obligations 639.8 1,560.2 737.7 3,797.0 6,734.7
Amounts recoverable through fuel adjustment (524.3 ) (776.5 ) (316.2 ) (1,306.7 ) (2,923.7 )
clause (B)
Total contractual obligations, net $ 115.5 $ 783.7 $ 421.5 $ 2,490.3 $ 3,811.0
(A) Maturities of the Company's long-term debt during the next five years consist
of $0.2 million, $300.2 million, $250.2 million, $110.2 million and $125.2
million in years 2013, 2014, 2015, 2016 and 2017, respectively.
(B) Includes expected recoveries of costs incurred for OG&E's railcar operating
lease obligations, OG&E's expected cogeneration energy payments, OG&E's
minimum fuel purchase commitments and OG&E's expected wind purchase
commitments.
OG&E also has 440 MWs of QF contracts to meet its current and future expected
customer needs. OG&E will continue reviewing all of the supply alternatives to
these QF contracts that minimize the total cost of generation to its customers,
including exercising its options (if applicable) to extend these QF contracts at
pre-determined rates.
Variances in the actual cost of fuel used in electric generation (which includes
the operating lease obligations for OG&E's railcar leases shown above) and
certain purchased power costs, as compared to the fuel component included in the
cost-of-service for ratemaking, are passed through to OG&E's customers through
fuel adjustment clauses. Accordingly, while the cost of fuel related to
operating leases and the vast majority of minimum fuel purchase commitments of
OG&E noted above may increase capital requirements, such costs are recoverable
through fuel adjustment clauses and have little, if any, impact on net capital
requirements and future contractual obligations. The fuel adjustment clauses are
subject to periodic review by the OCC, the APSC and the FERC.
Pension and Postretirement Benefit Plans
At December 31, 2012, 42.3 percent of the Pension Plan investments were in
listed common stocks with the balance primarily invested in U.S Government
securities, bonds, debentures and notes, a commingled fund and a common
collective trust as presented in Note 14 of Notes to Consolidated Financial
Statements. In 2012, asset returns on the Pension Plan were 10.6 percent due to
the gains in fixed income and equity investments. During the same time,
corporate bond yields, which are used in determining the discount rate for
future pension obligations, have continued to decline. During 2012 and 2011, OGE
Energy made contributions to its Pension Plan of $35 million and $50 million,
respectively, to help ensure that the Pension Plan maintains an adequate funded
status. The level of funding is dependent on returns on plan assets and future
discount rates. During 2013, OGE Energy expects to contribute up to $35 million
to its Pension Plan. OGE Energy could be required to make additional
contributions
66
--------------------------------------------------------------------------------if the value of its pension trust and postretirement benefit plan trust assets
are adversely impacted by a major market disruption in the future.
The following table presents the status of the Company's Pension Plan, the
Restoration of Retirement Income Plan and the postretirement benefit plans at
December 31, 2012 and 2011. These amounts have been recorded in Accrued Benefit
Obligations with the offset in Accumulated Other Comprehensive Loss (except
OG&E's portion which is recorded as a regulatory asset as discussed in Note 1 of
Notes to Consolidated Financial Statements) in the Company's Consolidated
Balance Sheet. The amounts in Accumulated Other Comprehensive Loss and those
recorded as a regulatory asset represent a net periodic benefit cost to be
recognized in the Consolidated Statements of Income in future periods.
Restoration of Retirement Postretirement
Pension Plan Income Plan Benefit Plans
December 31 (In millions) 2012 2011 2012 2011 2012 2011
Benefit obligations $ (747.1 ) $ (697.7 ) $ (14.5 ) $ (13.3 ) $ (301.0 ) $ (280.6 )
Fair value of plan assets 626.0 589.8 - - 59.6 61.0
Funded status at end of year $ (121.1 ) $ (107.9 ) $ (14.5 ) $ (13.3 ) $ (241.4 ) $ (219.6 )
Common Stock Dividends
The Company's dividend policy is reviewed by the Board of Directors at least
annually and is based on numerous factors, including management's estimation of
the long-term earnings power of its businesses. The Company's financial
objective includes increasing the dividend to meet the Company's dividend payout
objectives. The Company's target payout ratio is to pay out dividends no more
than 60 percent of its normalized earnings on an annual basis. The target payout
ratio has been determined after consideration of numerous factors, including the
largely retail composition of the Company's shareholder base, the Company's
financial position, the Company's growth targets, the composition of the
Company's assets and investment opportunities. At the Company's November 2012
Board meeting, management, after considering estimates of future earnings and
numerous other factors, recommended to the Board of Directors an increase in the
current quarterly dividend rate to $0.4175 per share from $0.3925 per share
effective with the Company's first quarter 2013 dividend.
Security Ratings
Moody's Standard &
Investors Poor's Ratings
Services Services Fitch Ratings
OG&E Senior Notes A2 BBB+ A+
Enogex LLC Notes Baa3 BBB- BBB
OGE Energy Senior Notes Baa1 BBB A-
OGE Energy Commercial Paper P2 A2 F2
Access to reasonably priced capital is dependent in part on credit and security
ratings. Generally, lower ratings lead to higher financing costs. Pricing grids
associated with the Company's credit facilities could cause annual fees and
borrowing rates to increase if an adverse rating impact occurs. The impact of
any future downgrade could include an increase in the costs of the Company's
short-term borrowings, but a reduction in the Company's credit ratings would not
result in any defaults or accelerations. Any future downgrade could also lead to
higher long-term borrowing costs and, if below investment grade, would require
the Company to post collateral or letters of credit. In the event Moody's
Investors Services or Standard & Poor's Ratings Services were to lower the
Company's senior unsecured debt rating to a below investment grade rating, at
December 31, 2012, the Company would have been required to post $0.2 million of
cash collateral to satisfy its obligation under its financial and physical
contracts relating to derivative instruments that are in a net liability
position at December 31, 2012. In addition, the Company could be required to
provide additional credit assurances in future dealings with third parties,
which could include letters of credit or cash collateral.
On June 20, 2012, Fitch Ratings downgraded OGE Energy Corp.'s short-term debt
rating from F1 to F2 and OGE Energy Corp.'s long-term debt issuer default rating
from A to A-. All other ratings (by Fitch Ratings) at OG&E and Enogex remained
unchanged and with a stable outlook. Fitch Ratings indicated that the downgrade
at OGE Energy Corp. was primarily due to concerns related to the uncertainties
associated with the environmental mandates at OG&E as well as Enogex's
sensitivity to commodity prices and growth strategy with the ArcLight group.
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A security rating is not a recommendation to buy, sell or hold securities. Such
rating may be subject to revision or withdrawal at any time by the credit rating
agency and each rating should be evaluated independently of any other rating.
Future financing requirements may be dependent, to varying degrees, upon
numerous factors such as general economic conditions, abnormal weather, load
growth, commodity prices, levels of drilling activity, acquisitions of other
businesses and/or development of projects, actions by rating agencies,
inflation, changes in environmental laws or regulations, rate increases or
decreases allowed by regulatory agencies, new legislation and market entry of
competing electric power generators.
2012 Capital Requirements, Sources of Financing, Purchase of Treasury Stock and
Financing Activities
Total capital requirements, consisting of capital expenditures and maturities of
long-term debt, were $1,351.8 million and contractual obligations, net of
recoveries through fuel adjustment clauses, were $112.8 million resulting in
total net capital requirements and contractual obligations of $1,464.6 million
in 2012, of which $12.9 million was to comply with environmental
regulations. This compares to net capital requirements of $1,446.2 million and
net contractual obligations of $111.1 million totaling $1,557.3 million in 2011,
of which $6.9 million was to comply with environmental regulations.
In 2012, the Company's sources of capital were cash generated from operations,
proceeds from the issuance of short-term debt, proceeds from Enogex's term loan
agreement, proceeds from the sales of common stock to the public through the
Company's Automatic Dividend Reinvestment and Stock Purchase Plan, funding for
growth opportunities at Enogex through the ArcLight group and quarterly
distributions from Enogex Holdings. Changes in working capital reflect the
seasonal nature of the Company's business, the revenue lag between billing and
collection from customers and fuel inventories. See "Working Capital" for a
discussion of significant changes in net working capital requirements as it
pertains to operating cash flow and liquidity.
Purchase of Treasury Stock
In November 2012, the Company purchased 60,000 shares of its common stock at an
average cost of $55.41 per share on the open market. These shares will be used
to satisfy Enogex's portion of the Company's obligation to deliver shares of
common stock related to long-term incentive payouts of earned performance units
in 2013. The Company expects to purchase shares in the future to satisfy a
portion of its obligation under its incentive plan.
Enogex Term Loan Agreement
On August 2, 2012, Enogex entered into a $250 million, three-year term loan
agreement with a maturity date of August 2, 2015. The loan was used to fund
capital expenditures and for working capital purposes.
Potential Collateral Requirements
Derivative instruments are utilized in managing the Company's commodity price
exposures and in Enogex's asset management and hedging activities executed on
behalf of the Company. Agreements governing the derivative instruments may
require the Company to provide collateral in the form of cash or a letter of
credit in the event mark-to-market exposures exceed contractual thresholds or
the Company's credit ratings are lowered. Future collateral requirements are
uncertain, and are subject to terms of the specific agreements and to
fluctuations in natural gas and NGLs market prices.
On July 21, 2010, President Obama signed into law the Dodd-Frank Act. Among
other things, the Dodd-Frank Act provides for a new regulatory regime for
derivatives, including mandatory clearing of certain swaps and margin
requirements. The Dodd-Frank Act contains provisions that should exempt certain
derivatives end-users such as the Company from much of the clearing
requirements. The regulations require that the decision on whether to use the
end-user exception from mandatory clearing for derivative transactions be
reviewed and approved by an "appropriate committee" of the Board of Directors.
The scope of the margin requirements and their potential direct impact on the
Company remain unclear because final rules have not been issued. Further, even
if the Company qualifies for the end-user exception to clearing and margin
requirements are not imposed on end-users, its derivative counterparties may be
subject to new capital, margin and business conduct requirements as a result of
the new regulations, which may increase the Company's transaction costs or make
it more difficult to enter into derivative transactions on favorable terms. The
Company's inability to enter into derivative transactions on favorable terms, or
at all, could increase operating expenses and put the Company at increased
exposure to risks of adverse changes in commodities prices. The impact of the
provisions of the Dodd-Frank Act on the Company cannot be fully determined at
this time due to uncertainty over forthcoming regulations and potential changes
to the derivatives markets arising from new regulatory requirements.
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Management expects that cash generated from operations, proceeds from the
issuance of long and short-term debt and proceeds from the sales of common stock
to the public through the Company's Automatic Dividend Reinvestment and Stock
Purchase Plan or other offerings will be adequate over the next three years to
meet anticipated cash needs and to fund future growth
opportunities. Additionally, the Company will have an additional source of
funding for growth opportunities at Enogex through the ArcLight group and from
quarterly distributions from Enogex Holdings. The Company utilizes short-term
borrowings (through a combination of bank borrowings and commercial paper) to
satisfy temporary working capital needs and as an interim source of financing
capital expenditures until permanent financing is arranged.
Short-Term Debt and Credit Facilities
Short-term borrowings generally are used to meet working capital
requirements. The Company borrows on a short-term basis, as necessary, by the
issuance of commercial paper and by borrowings under its revolving credit
agreements. The Company has revolving credit facilities totaling in the
aggregate $1,550.0 million. These bank facilities can also be used as letter of
credit facilities. The short-term debt balance was $430.9 million and $277.1
million at December 31, 2012 and 2011, respectively. The weighted-average
interest rate on short-term debt at December 31, 2012 was 0.43 percent. The
average balance of short-term debt in 2012 was $451.0 million at a
weighted-average interest rate of 0.45 percent. The maximum month-end balance of
short-term debt in 2012 was $608.2 million. At December 31, 2012, Enogex had no
outstanding borrowings under its revolving credit agreement as compared to
$150.0 million at December 31, 2011. As Enogex LLC's credit agreement matures on
December 13, 2016, along with its intent in utilizing its credit agreement,
borrowings thereunder are classified as long-term debt in the Company's
Consolidated Balance Sheets. At December 31, 2012, the Company had $1,116.9
million of net available liquidity under its revolving credit agreements. OG&E
has the necessary regulatory approvals to incur up to $800 million in short-term
borrowings at any one time for a two-year period beginning January 1, 2013 and
ending December 31, 2014. At December 31, 2012, the Company had $1.8 million in
cash and cash equivalents. See Note 13 of Notes to Consolidated Financial
Statements for a discussion of the Company's short-term debt activity.
Expected Issuance of Long-Term Debt
OG&E expects to issue up to $250 million of long-term debt in the first half of
2013, depending on market conditions, to fund capital expenditures, repay
short-term borrowings and for general corporate purposes.
Common Stock
The Company expects to issue between $12 million and $15 million of common stock
in its Automatic Dividend Reinvestment and Stock Purchase Plan in 2013. See Note
11 of Notes to Consolidated Financial Statements for a discussion of the
Company's common stock activity.
Minimum Quarterly Distributions by Enogex Holdings
Pursuant to the Enogex Holdings LLC Agreement, Enogex Holdings will make minimum
quarterly distributions equal to the amount of cash required to cover OGE
Energy's anticipated tax liabilities plus $12.5 million, to be distributed in
proportion to each member's percentage ownership interest.
Critical Accounting Policies and Estimates
The Consolidated Financial Statements and Notes to Consolidated Financial
Statements contain information that is pertinent to Management's Discussion and
Analysis. In preparing the Consolidated Financial Statements, management is
required to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and contingent
liabilities at the date of the Consolidated Financial Statements and the
reported amounts of revenues and expenses during the reporting period. Changes
to these assumptions and estimates could have a material effect on the Company's
Consolidated Financial Statements. However, the Company believes it has taken
reasonable, but conservative, positions where assumptions and estimates are used
in order to minimize the negative financial impact to the Company that could
result if actual results vary from the assumptions and estimates. In
management's opinion, the areas of the Company where the most significant
judgment is exercised for all Company segments includes the determination of
Pension Plan assumptions, impairment estimates of long-lived assets (including
intangible assets) income taxes, contingency reserves, asset retirement
obligations, fair value and cash flow hedges and the allowance for uncollectible
accounts receivable. For the electric utility segment, the most significant
judgment is also exercised in the valuation of regulatory assets and liabilities
and unbilled revenues. For the natural gas transportation and storage segment
and the natural gas gathering and processing segment, the most significant
judgment is also exercised in the
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valuation of operating revenues, natural gas purchases, purchase and sale
contracts, assets and depreciable lives of property, plant and equipment,
amortization methodologies related to intangible assets and impairment
assessments of goodwill. The selection, application and disclosure of the
following critical accounting estimates have been discussed with the Company's
Audit Committee. The Company discusses its significant accounting policies,
including those that do not require management to make difficult, subjective, or
complex judgments or estimates, in Note 1 of Notes to Consolidated Financial
Statements.
Consolidated (including all Company segments)
Pension and Postretirement Benefit Plans
The Company has a Pension Plan that covers a significant amount of the Company's
employees hired before December 1, 2009. Also, effective December 1, 2009, the
Company's Pension Plan is no longer being offered to employees hired on or after
December 1, 2009. The Company also has defined benefit postretirement plans that
cover a significant amount of its employees. Pension and other postretirement
plan expenses and liabilities are determined on an actuarial basis and are
affected by the market value of plan assets, estimates of the expected return on
plan assets, assumed discount rates and the level of funding. Actual changes in
the fair market value of plan assets and differences between the actual return
on plan assets and the expected return on plan assets could have a material
effect on the amount of pension expense ultimately recognized. The pension plan
rate assumptions are shown in Note 14 of Notes to Consolidated Financial
Statements. The assumed return on plan assets is based on management's
expectation of the long-term return on the plan assets portfolio. The discount
rate used to compute the present value of plan liabilities is based generally on
rates of high-grade corporate bonds with maturities similar to the average
period over which benefits will be paid. The level of funding is dependent on
returns on plan assets and future discount rates. Higher returns on plan assets
and an increase in discount rates will reduce funding requirements to the
Pension Plan. The following table indicates the sensitivity of the Pension Plan
funded status to these variables.
Change Impact on Funded Status
Actual plan asset returns +/- 1 percent +/- $6.3 million
Discount rate +/- 0.25 percent +/- $16.7 million
Contributions +/- $10 million +/- $10 million
Assessing Impairment of Long-Lived Assets (Including Intangible Assets) and
Goodwill
The Company assesses its long-lived assets, including intangible assets with
finite useful lives, for impairment when there is evidence that events or
changes in circumstances require an analysis of the recoverability of an asset's
carrying amount. Estimates of future cash flows used to test the recoverability
of long-lived assets and intangible assets shall include only the future cash
flows (cash inflows less associated cash outflows) that are directly associated
with and that are expected to arise as a direct result of the use and eventual
disposition of the asset. The fair value of these assets is based on third-party
evaluations, prices for similar assets, historical data and projected cash
flows. An impairment loss is recognized when the sum of the expected future net
cash flows is less than the carrying amount of the asset. The amount of any
recognized impairment is based on the estimated fair value of the asset subject
to impairment compared to the carrying amount of such asset. In 2011, the
Company recorded a pre-tax impairment loss of $5.0 million, of which $2.5
million was the noncontrolling interest portion (see Note 5 of Notes to
Consolidated Financial Statements), related to the Atoka processing plant. The
Company recorded no other material impairments in 2012, 2011 or 2010.
As a result of the gas gathering acquisitions in November 2011, Enogex recorded
goodwill of $39.4 million. Enogex assesses its goodwill for impairment at least
annually as of October 1 by comparing the fair value of the reporting unit with
its book value, including goodwill. Enogex utilizes the income approach
(generally accepted valuation approach) to estimate the fair value of the
reporting unit, also giving consideration to alternative methods such as the
market and cost approaches. Under the income approach, anticipated cash flows
over a period of years plus a terminal value are discounted to present value
using appropriate discount rates. Enogex performs its goodwill impairment
testing at the natural gas gathering and processing segment reporting unit
level. Enogex recorded no impairments of goodwill in 2012.
Income Taxes
The Company uses the asset and liability method of accounting for income taxes.
Under this method, a deferred tax asset or liability is recognized for the
estimated future tax effects attributable to temporary differences between the
financial statement basis and the tax basis of assets and liabilities as well as
tax credit carry forwards and net operating loss carry forwards. Deferred tax
assets and liabilities are measured using enacted tax rates expected to apply to
taxable income in the years in which those
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temporary differences are expected to be recovered or settled. The effect on
deferred tax assets and liabilities of a change in tax rates is recognized in
the period of the change.
The application of income tax law is complex. Laws and regulations in this area
are voluminous and often ambiguous. Interpretations and guidance surrounding
income tax laws and regulations change over time. Accordingly, it is necessary
to make judgments regarding income tax exposure. As a result, changes in these
judgments can materially affect amounts the Company recognized in its
consolidated financial statements. Tax positions taken by the Company on its
income tax returns that are recognized in the financial statements must satisfy
a more likely than not recognition threshold, assuming that the position will be
examined by taxing authorities with full knowledge of all relevant information.
Commitments and Contingencies
In the normal course of business, the Company is confronted with issues or
events that may result in a contingent liability. These generally relate to
lawsuits or claims made by third parties, including governmental agencies. When
appropriate, management consults with legal counsel and other appropriate
experts to assess the claim. If, in management's opinion, the Company has
incurred a probable loss as set forth by GAAP, an estimate is made of the loss
and the appropriate accounting entries are reflected in the Company's
Consolidated Financial Statements.
Except as disclosed otherwise in this Form 10-K, the Company believes that any
reasonably possible losses in excess of accrued amounts arising out of pending
or threatened lawsuits or claims would not be quantitatively material to its
financial statements and would not have a material adverse effect on the
Company's consolidated financial position, results of operations or cash flows.
See Notes 16 and 17 of Notes to Consolidated Financial Statements and Item 3 of
Part I in this Form 10-K for a discussion of the Company's commitments and
contingencies.
Asset Retirement Obligations
The Company has previously recorded asset retirement obligations that are being
amortized over their respective lives ranging from three months to 74 years. The
Company also has certain asset retirement obligations primarily related to
Enogex's processing plants and compression sites that have not been recorded
because the Company cannot determine when these obligations will be incurred.
The inputs used in the valuation of asset retirement obligations include the
assumed life of the asset placed into service, the average inflation rate,
market risk premium, the credit-adjusted risk free interest rate and the timing
of incurring costs related to the retirement of the asset.
Hedging Policies
The Company designates as cash flow hedges derivatives used to manage commodity
price risk exposure for Enogex's NGLs volumes and corresponding keep-whole
natural gas resulting from its natural gas processing contracts (processing
hedges) and natural gas positions resulting from its natural gas gathering and
processing operations and natural gas transportation and storage operations
(operational gas hedges). The Company also designates as cash flow hedges
certain derivatives used to manage natural gas commodity exposure for certain
natural gas storage inventory positions. Hedges are evaluated prior to execution
with respect to the impact on the volatility of forecasted earnings and are
evaluated at least quarterly after execution for the impact on earnings.
Enogex's cash flow hedges at December 31, 2012 mature by the end of the first
quarter of 2013.
From time to time, OG&E and Enogex may engage in cash flow and fair value hedge
transactions to modify interest rate exposure and not to modify the overall
leverage of the debt portfolio.
Electric Utility Segment
Regulatory Assets and Liabilities
OG&E, as a regulated utility, is subject to accounting principles for certain
types of rate-regulated activities, which provide that certain actual or
anticipated costs that would otherwise be charged to expense can be deferred as
regulatory assets, based on the expected recovery from customers in future
rates. Likewise, certain actual or anticipated credits that would otherwise
reduce expense can be deferred as regulatory liabilities, based on the expected
flowback to customers in future rates. Management's expected recovery of
deferred costs and flowback of deferred credits generally results from specific
decisions by regulators granting such ratemaking treatment.
OG&E records certain actual or anticipated costs and obligations as regulatory
assets or liabilities if it is probable, based on regulatory orders or other
available evidence, that the cost or obligation will be included in amounts
allowable for recovery or
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refund in future rates. The benefit obligations regulatory asset is comprised of
expenses recorded which are probable of future recovery and that have not yet
been recognized as components of net periodic benefit cost, including net loss,
prior service cost and net transition obligation.
Unbilled Revenues
OG&E reads its customers' meters and sends bills to its customers throughout
each month. As a result, there is a significant amount of customers' electricity
consumption that has not been billed at the end of each month. Unbilled revenue
is presented in Accrued Unbilled Revenues on the Consolidated Balance Sheets and
in Operating Revenues on the Consolidated Statements of Income based on
estimates of usage and prices during the period. At December 31, 2012, if the
estimated usage or price used in the unbilled revenue calculation were to
increase or decrease by one percent, this would cause a change in the unbilled
revenues recognized of $0.3 million. At December 31, 2012 and 2011, Accrued
Unbilled Revenues were $57.4 million and $59.3 million, respectively. The
estimates that management uses in this calculation could vary from the actual
amounts to be paid by customers.
Allowance for Uncollectible Accounts Receivable
Customer balances are generally written off if not collected within six months
after the final billing date. The allowance for uncollectible accounts
receivable for OG&E is calculated by multiplying the last six months of electric
revenue by the provision rate. The provision rate is based on a 12-month
historical average of actual balances written off. To the extent the historical
collection rates are not representative of future collections, there could be an
effect on the amount of uncollectible expense recognized. Also, a portion of the
uncollectible provision related to fuel is being recovered through the fuel
adjustment clause. At December 31, 2012, if the provision rate were to increase
or decrease by 10 percent, this would cause a change in the uncollectible
expense recognized of $0.3 million. The allowance for uncollectible accounts
receivable is a reduction to Accounts Receivable on the Consolidated Balance
Sheets and is included in Other Operation and Maintenance Expense on the
Consolidated Statements of Income. The allowance for uncollectible accounts
receivable was $2.6 million and $3.7 million at December 31, 2012 and 2011,
respectively.
Natural Gas Transportation and Storage and Natural Gas Gathering and Processing
Segments
Operating Revenues
Operating revenues for gathering, processing, transportation and storage
services for Enogex are recorded each month based on the current month's
estimated volumes, contracted prices (considering current commodity prices),
historical seasonal fluctuations and any known adjustments. The estimates are
reversed in the following month and customers are billed on actual volumes and
contracted prices. Gas sales are calculated on current-month nominations and
contracted prices. Operating revenues associated with the production of NGLs are
estimated based on current-month estimated production and contracted
prices. These amounts are reversed in the following month and the customers are
billed on actual production and contracted prices. Estimated operating revenues
are reflected in Accounts Receivable on the Consolidated Balance Sheets and in
Operating Revenues on the Consolidated Statements of Income.
Enogex recognizes revenue from natural gas gathering, processing, transportation
and storage services to third parties as services are provided. Revenue
associated with NGLs is recognized when the production is sold.
Enogex records deferred revenue when it receives consideration from a third
party before achieving certain criteria that must be met for revenue to be
recognized in accordance with GAAP. In August 2010, Enogex completed
construction of transportation and compression facilities necessary to provide
gas delivery service to a new natural gas-fired electric generation facility
near Pryor, Oklahoma. Aid in Construction payments of $36.4 million received in
excess of construction costs were recognized as Deferred Revenues on the
Company's Consolidated Balance Sheet and are being amortized on a straight-line
basis of $1.2 million per year over the life of the related firm transportation
service agreement under which service commenced in June 2011. Also, in August
2011, Enogex and one of its five largest customers entered into new agreements,
effective July 1, 2011, relating to the customer's natural gas gathering and
processing volumes on the Oklahoma portion of Enogex's system. As a result,
Enogex has recorded $7.1 million in Deferred Revenues on the Company's
Consolidated Balance Sheet at December 31, 2012, which are expected to be
recognized based on the estimated average fee per MMBtu processed by the end of
2014. Enogex has also recorded $1.5 million in Deferred Revenues on the
Company's Consolidated Balance Sheet at December 31, 2012 in connection with
other gathering and processing agreements.
Enogex engages in asset management and hedging activities related to the
purchase and sale of natural gas and NGLs. Contracts utilized in these
activities generally include purchases and sales for physical delivery,
over-the-counter forward swap and options contracts and exchange traded futures
and options. Enogex's transactions that qualify as derivatives are reflected at
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fair value with the resulting unrealized gains and losses recorded as PRM Assets
or Liabilities in the Consolidated Balance Sheets, classified as current or
long-term based on their anticipated settlement, or against the brokerage
deposits in Other Current Assets. The offsetting unrealized gains and losses
from changes in the market value of open contracts are included in Operating
Revenues in the Consolidated Statements of Income or in Other Comprehensive
Income for derivatives designated and qualifying as cash flow hedges. Contracts
resulting in delivery of a commodity are included as sales or purchases in the
Consolidated Statements of Income as Operating Revenues or Cost of Goods Sold
depending on whether the contract relates to the sale or purchase of the
commodity.
Natural Gas Purchases
Estimates for gas purchases are based on estimated volumes and contracted
purchase prices. Estimated gas purchases are included in Accounts Payable on the
Consolidated Balance Sheets and in Cost of Goods Sold on the Consolidated
Statements of Income.
Purchase and Sale Contracts
Enogex utilizes purchases and sales for physical delivery, over-the-counter
forward swap and options contracts and exchange traded futures and options.
These activities either qualify as derivatives and are recorded at fair market
value or qualify for normal purchase normal sale treatment. Enogex's portfolio
is marked to estimated fair market value on a daily basis. When available,
actual market prices are utilized in determining the value of natural gas and
related derivative commodity instruments. For longer-term positions, which are
limited to a maximum of 60 months and certain short-term positions for which
market prices are not available, models based on forward price curves are
utilized. These models incorporate estimates and assumptions as to a variety of
factors such as pricing relationships between various energy commodities and
geographic location. Actual experience can vary significantly from these
estimates and assumptions.
In nearly all cases, independent market prices are obtained and compared to the
values used in determining the fair value. The recorded value of the energy
contracts may change significantly in the future as the market price for the
commodity changes, but the value of transactions not designated as cash flow
hedges is subject to mark-to-market risk loss limitations provided under the
Company's risk policies. Management utilizes models to estimate the fair value
of the Company's energy contracts including derivatives that do not have an
independent market price. At December 31, 2012, unrealized mark-to-market losses
were $0.2 million, none of which were calculated utilizing models. At
December 31, 2012, a price movement of one percent for prices verified by
independent parties would result in unrealized mark-to-market gains or losses of
less than $0.1 million and a price movement of five percent on model-based
prices would result in unrealized mark-to-market gains or losses of less than
$0.1 million.
Valuation of Assets
The application of business combination and impairment accounting requires
Enogex to use significant estimates and assumptions in determining the fair
value of assets and liabilities. The acquisition method of accounting for
business combinations requires Enogex to estimate the fair value of assets
acquired and liabilities assumed to allocate the proper amount of the purchase
price consideration between goodwill and the assets that are depreciated and
amortized. Enogex records intangible assets separately from goodwill and
amortizes intangible assets with finite lives over their estimated useful life
as determined by management. Enogex does not amortize goodwill but instead
annually assesses goodwill for impairment.
In 2011 and 2012, Enogex completed gas gathering acquisitions accounted for as
business combinations as discussed in Note 3 of Notes to Consolidated Financial
Statements. As part of these acquisitions, Enogex has engaged the services of a
third-party valuation expert to assist it in determining the fair value of the
acquired assets and liabilities, including goodwill; however, the ultimate
determination of those values is the responsibility of Enogex's management.
Enogex bases its estimates on assumptions believed to be reasonable, but which
are inherently uncertain. These valuations require the use of management's
assumptions, which would not reflect unanticipated events and circumstances that
may occur.
Depreciable Lives of Property, Plant and Equipment and Amortization
Methodologies Related to Intangible Assets
The computation of depreciation expense requires judgment regarding the
estimated useful lives and salvage value of assets at the time the assets are
placed in service. As circumstances warrant, useful lives are adjusted when
changes in planned use, changes in estimated production lives of affiliated
natural gas basins or other factors indicate that a different life would be more
appropriate. Such changes could materially impact future depreciation expense.
Changes in useful lives that do not result in the impairment of an asset are
recognized prospectively. The computation of amortization expense on intangible
assets requires
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judgment regarding the amortization method used. Intangible assets are amortized
on a straight-line basis over their useful lives using a method of amortization
that reflects the pattern in which the economic benefits of the intangible asset
are consumed.
Natural Gas Inventory
Natural gas inventory is held by Enogex, through its transportation and storage
business, to provide operational support for its pipeline deliveries and to
manage its leased storage capacity. In an effort to mitigate market price
exposures, Enogex may enter into contracts or hedging instruments to protect the
cash flows associated with its inventory. All natural gas inventory held by
Enogex is valued using moving average cost and is recorded at the lower of cost
or market. As part of its asset management activity, Enogex injects and
withdraws natural gas into and out of inventory under the terms of its storage
capacity contracts. During the years ended December 31, 2012, 2011 and 2010,
Enogex recorded write-downs to market value related to natural gas storage
inventory of $5.5 million, $4.8 million and $0.3 million, respectively. The
amount of Enogex's natural gas inventory was $16.5 million and $23.7 million at
December 31, 2012 and 2011, respectively. The cost of gas associated with sales
of natural gas storage inventory is presented in Cost of Goods Sold on the
Consolidated Statements of Income.
Allowance for Uncollectible Accounts Receivable
The allowance for uncollectible accounts receivable for Enogex is calculated
based on outstanding accounts receivable balances over 180 days old. In
addition, other outstanding accounts receivable balances less than 180 days old
are reserved on a case-by-case basis when Enogex believes the collection of
specific amounts owed is unlikely to occur. The allowance for uncollectible
accounts receivable is a reduction to Accounts Receivable on the Consolidated
Balance Sheets and is included in Other Operation and Maintenance Expense on the
Consolidated Statements of Income. The aggregate allowance for uncollectible
accounts receivable for Enogex's natural gas transportation and storage and
natural gas gathering and processing segments was less than $0.1 million at
December 31, 2012 and 2011.
Accounting Pronouncements
See Note 2 of Notes to Consolidated Financial Statements for discussion of
current accounting pronouncements that are applicable to the Company.
Commitments and Contingencies
In the normal course of business, the Company is confronted with issues or
events that may result in a contingent liability. These generally relate to
lawsuits or claims made by third parties, including governmental agencies. When
appropriate, management consults with legal counsel and other appropriate
experts to assess the claim. If, in management's opinion, the Company has
incurred a probable loss as set forth by GAAP, an estimate is made of the loss
and the appropriate accounting entries are reflected in the Company's
Consolidated Financial Statements. At the present time, based on currently
available information, except as disclosed otherwise in this Form 10-K, the
Company believes that any reasonably possible losses in excess of accrued
amounts arising out of pending or threatened lawsuits or claims would not be
quantitatively material to its financial statements and would not have a
material adverse effect on the Company's consolidated financial position,
results of operations or cash flows. See Notes 16 and 17 of Notes to
Consolidated Financial Statements and Item 3 of Part I in this Form 10-K for a
discussion of the Company's commitments and contingencies.
Environmental Laws and Regulations
The activities of OG&E and Enogex are subject to stringent and complex Federal,
state and local laws and regulations governing environmental protection
including the discharge of materials into the environment. These laws and
regulations can restrict or impact OG&E's and Enogex's business activities in
many ways, such as restricting the way it can handle or dispose of their wastes,
requiring remedial action to mitigate pollution conditions that may be caused by
their operations or that are attributable to former operators, regulating future
construction activities to mitigate harm to threatened or endangered species and
requiring the installation and operation of pollution control equipment. Failure
to comply with these laws and regulations may result in the assessment of
administrative, civil and criminal penalties, the imposition of remedial
requirements and the issuance of orders enjoining future operations. OG&E and
Enogex believe that their operations are in substantial compliance with current
Federal, state and local environmental standards.
Environmental regulation can increase the cost of planning, design, initial
installation and operation of OG&E's or Enogex's facilities. Historically,
OG&E's and Enogex's total expenditures for environmental control facilities and
for remediation have not been significant in relation to its consolidated
financial position or results of operations. The Company believes, however,
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that it is reasonably likely that the trend in environmental legislation and
regulations will continue towards more restrictive standards. Compliance with
these standards is expected to increase the cost of conducting business.
OG&E expects that significant future capital expenditures necessary to comply
with the environmental laws and regulations discussed below will qualify as part
of a pre-approval plan to handle state and Federally mandated environmental
upgrades which will be recoverable in Oklahoma from OG&E's retail customers
under House Bill 1910, which was enacted into law in May 2005.
It is estimated that OG&E's and Enogex's total expenditures to comply with
environmental laws, regulations and requirements for 2013 will be $63.0 million
and $6.4 million, respectively, of which $45.3 million and $0.7 million,
respectively, are for capital expenditures. It is estimated that OG&E's and
Enogex's total expenditures to comply for environmental laws, regulations and
requirements for 2014 will be $37.7 million and $6.3 million, respectively, of
which $19.2 million and $0.5 million, respectively, are for capital
expenditures. The amounts for OG&E above include capital expenditures for low
NOX burners and exclude certain other capital expenditures as discussed in the
capital expenditures table and related footnote D in "Future Capital
Requirements and Financing Activities" above. The Company's management believes
that all of its operations are in substantial compliance with current Federal,
state and local environmental standards. Management continues to evaluate its
compliance with existing and proposed environmental legislation and regulations
and implement appropriate environmental programs in a competitive market.
Air
Federal Clean Air Act Overview
OG&E's and Enogex's operations are subject to the Federal Clean Air Act, as
amended, and comparable state laws and regulations. These laws and regulations
regulate emissions of air pollutants from various industrial sources, including
electric generating units, natural gas processing plants and compressor
stations, and also impose various monitoring and reporting requirements. Such
laws and regulations may require that OG&E and Enogex obtain pre-approval for
the construction or modification of certain projects or facilities expected to
produce air emissions or result in the increase of existing air emissions,
obtain and strictly comply with air permits containing various emissions and
operational limitations or install emission control equipment. OG&E and Enogex
likely will be required to incur certain capital expenditures in the future for
air pollution control equipment and technology in connection with obtaining and
maintaining operating permits and approvals for air emissions.
Regional Haze Control Measures
On June 15, 2005, the EPA issued final amendments to its 1999 regional haze
rule. Regional haze is visibility impairment caused by the cumulative air
pollutant emissions from numerous sources over a wide geographic area. The
regional haze rule is intended to protect visibility in certain national parks
and wilderness areas throughout the United States. In Oklahoma, the Wichita
Mountains are the only area covered under the rule. However, Oklahoma's impact
on parks in other states must also be evaluated.
As required by the Federal regional haze rule, the state of Oklahoma evaluated
the installation of BART to reduce emissions that cause or contribute to
regional haze from certain sources within the state that were built between 1962
and 1977. Certain of OG&E's units at the Horseshoe Lake, Seminole, Muskogee and
Sooner generating stations were evaluated for BART. On February 18, 2010,
Oklahoma submitted its SIP to the EPA, which set forth the state's plan for
compliance with the Federal regional haze rule. The SIP was subject to the EPA's
review and approval.
The Oklahoma SIP included requirements for reducing emissions of NOX and SO2
from OG&E's seven BART-eligible units at the Seminole, Muskogee and Sooner
generating stations. The SIP also included a waiver from BART requirements for
all eligible units at the Horseshoe Lake generating station based on air
modeling that showed no significant impact on visibility in nearby national
parks and wilderness areas. The SIP concluded that BART for reducing NOX
emissions at all of the subject units should be the installation of low NOX
burners with overfire air (flue gas recirculation was also required on two of
the units) and set forth associated NOX emission rates and limits. OG&E
preliminarily estimates that the total capital cost of installing and operating
these NOX controls on all covered units, based on recent industry experience and
past projects, will be approximately $95 million. With respect to SO2 emissions,
the SIP included an agreement between the Oklahoma Department of Environmental
Quality and OG&E that established BART for SO2 control at the four affected
coal-fired units located at OG&E's Sooner and Muskogee generating stations as
the continued use of low sulfur coal (along with associated emission rates and
limits). The SIP specifically rejected the installation and operation of Dry
Scrubbers as BART for SO2 control from these units because the state determined
that Dry Scrubbers were not cost effective on these units.
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On December 28, 2011, the EPA issued a final rule in which it rejected portions
of the Oklahoma SIP and issued a FIP in their place. While the EPA accepted
Oklahoma's BART determination for NOX in the final rule, it rejected Oklahoma's
SO2 BART determination with respect to the four coal-fired units at the Sooner
and Muskogee generating stations. The EPA is instead requiring that OG&E meet an
SO2 emission rate of 0.06 pounds per MMBtu within five years. OG&E could meet
the proposed standard by either installing and operating Dry Scrubbers or fuel
switching at the four affected units. OG&E estimates that installing Dry
Scrubbers on these units would include capital costs to OG&E of more than $1.0
billion. OG&E and the state of Oklahoma filed an administrative stay request
with the EPA on February 24, 2012. The EPA has not yet responded to this
request. OG&E and other parties also filed a petition for review of the FIP in
the U.S. Court of Appeals for the Tenth Circuit on February 24, 2012 and a stay
request on April 4, 2012. On June 22, 2012, the U.S. Court of Appeals for the
Tenth Circuit granted the stay request. The stay will remain in place until a
decision on the petition for review is complete, which will delay the
implementation of the regional haze rule in Oklahoma. The merits of the appeal
have been fully briefed and oral argument is scheduled to occur on March 6,
2013. Neither the outcome of the appeal nor the timing of any required
expenditures for pollution control equipment can be predicted with any certainty
at this time.
Cross-State Air Pollution Rule
On July 7, 2011, the EPA finalized its Cross-State Air Pollution Rule to replace
the former Clean Air Interstate Rule that was remanded by a Federal court as a
result of legal challenges. The final rule would require 27 states to reduce
power plant emissions that contribute to ozone and particulate matter pollution
in other states. On December 27, 2011, the EPA published a supplemental rule,
which would make six additional states, including Oklahoma, subject to the
Cross-State Air Pollution Rule for NOX emissions during the ozone-season from
May 1 through September 30. Under the rule, OG&E would have been required to
reduce ozone-season NOX emissions from its electrical generating units within
the state beginning in 2012. The Cross-State Air Pollution Rule was challenged
in court by numerous states and power generators. On December 30, 2011, the U.S.
Court of Appeals issued a stay of the rule, which includes the supplemental
rule, pending a decision on the merits. By order dated August 21, 2012, the U.S.
Court of Appeals vacated the Cross-State Air Pollution Rule and ordered the EPA
to promulgate a replacement rule. On January 25, 2013, the U.S. Court of Appeals
denied the EPA's request for an en banc reconsideration of the court's decision
vacating the rule. OG&E cannot predict the outcome of such challenges.
Hazardous Air Pollutants Emission Standards
On April 16, 2012, regulations governing emissions of certain hazardous air
pollutants from electric generating units were published as the final MATS rule.
This rule includes numerical standards for particulate matter (as a surrogate
for toxic metals), hydrogen chloride and mercury emissions from coal-fired
boilers. In addition, the regulations include work practice standards for
dioxins and furans. Compliance is required within three years after the
effective date of the rule with the possibility of a one-year extension. To
comply with this rule, OG&E is currently planning to utilize activated carbon
injection and low levels of dry sorbent injection at each of its five coal-fired
units. Due to various uncertainties about the final design, the potential use of
this technology relating to regional haze measures and the specifications for
the control equipment, the resulting cost estimates currently range from $34
million to $72 million per unit. OG&E is evaluating the results of field testing
to finalize cost estimates and implementation schedules. The final MATS rule has
been appealed by several parties. OG&E is not a party to the appeals and cannot
predict the outcome of any such appeals.
Notice of Violation
In July 2008, OG&E received a request for information from the EPA regarding
Federal Clean Air Act compliance at OG&E's Muskogee and Sooner generating
plants. In recent years, the EPA has issued similar requests to numerous other
electric utilities seeking to determine whether various maintenance, repair and
replacement projects should have required permits under the Federal Clean Air
Act's new source review process. In January 2012, OG&E received a supplemental
request for an update of the previously provided information and for some
additional information not previously requested. On May 1, 2012, OG&E responded
to the EPA's supplemental request for information. OG&E believes it has acted in
full compliance with the Federal Clean Air Act and new source review process and
is cooperating with the EPA. On April 26, 2011, the EPA issued a notice of
violation alleging that 13 projects occurred at OG&E's Muskogee and Sooner
generating plants between 1993 and 2006 without the required new source review
permits. The notice of violation also alleges that OG&E's visible emissions at
its Muskogee and Sooner generating plants are not in accordance with applicable
new source performance standards. OG&E has met with the EPA regarding the notice
but cannot predict at this time what, if any, further actions may be necessary
as a result of the notice. The EPA could seek to require OG&E to install
additional pollution control equipment and pay fines and significant penalties
as a result of the allegations in the notice of violation. Section 113 of the
Federal Clean Air Act (along with the Federal Civil Penalties Inflation
Adjustment Act of 1996) provides for civil penalties as much as $37,500 per day
for each violation. The cost of any required pollution control equipment could
also be significant.
76--------------------------------------------------------------------------------National Ambient Air Quality Standards
The EPA is required to set NAAQS for certain pollutants considered to be harmful
to public health or the environment. The Clean Air Act requires the EPA to
review each NAAQS every five years. As a result of these reviews, the EPA
periodically has taken action to adopt more stringent NAAQS for those
pollutants. If any areas of Oklahoma were to be designated as not attaining the
NAAQS for a particular pollutant, the Company could be required to install
additional emission controls on its facilities to help the state achieve
attainment with the NAAQS. As of the end of 2012, no areas of Oklahoma had been
designated as non-attainment for pollutants that are likely to affect the
Company's operations. Several processes are under way to designate areas in
Oklahoma as attaining or not attaining revised NAAQS. The Company is monitoring
those processes and their possible impact on its operations but, at this time,
cannot determine with any certainty whether they will cause a material impact to
the Company's financial results.
Acid Rain Program
The Federal Clean Air Act includes an Acid Rain Program. The goal of the Acid
Rain Program is to achieve environmental and public health benefits through
reductions in SO2 and NOX emissions, which are the primary causes of acid rain.
To achieve this goal, the program employs both traditional and market-based
approaches for controlling air pollution.
The Acid Rain Program introduces an allowance trading system that uses the free
market to reduce pollution. Under this system, affected utility units are
allocated allowances based on their historic fuel consumption and a specific
emissions rate. Each allowance permits a unit to emit one ton of SO2 from the
chimney during or after a specified year. For each ton of SO2 emitted in a given
year, one allowance is retired, that is, it can no longer be used. Allowances
may be bought, sold or banked.
During Phase II of the program (now in effect), the Federal Clean Air Act set a
permanent ceiling (or cap) of 8.95 million total annual allowances allocated to
utilities. This cap firmly restricts emissions and ensures that environmental
benefits will be achieved and maintained. Due to OG&E's earlier decision to burn
low sulfur coal, these restrictions have had no significant financial impact.
The Acid Rain Program also focuses on one set of sources that emit NOX,
coal-fired electric utility boilers. As with the SO2 emission reduction
requirements, the NOX program was implemented in two phases, beginning in 1996
and 2000. The NOX program embodies many of the same principles of the SO2
trading program. However, it does not cap NOX emissions as the SO2 program does,
nor does it utilize an allowance trading system.
Emission limitations for NOX focus on the emission rate to be achieved
(expressed in pounds of NOX per MMBtu of heat input). In general, two options
for compliance with the emission limitations are provided: compliance with an
individual emission rate for a boiler; or averaging of emission rates over two
or more units to meet an overall emission rate limitation.
Since becoming subject to the Acid Rain Program, OG&E has met all obligations
and limitations requirements.
Climate Change and Greenhouse Gas Emissions
There is continuing discussion and evaluation of possible global climate change
in certain regulatory and legislative arenas. The focus is generally on
emissions of greenhouse gases, including carbon dioxide, sulfur hexafluoride and
methane, and whether these emissions are contributing to the warming of the
Earth's atmosphere. There are various international agreements that restrict
greenhouse gas emissions, but none of them have a binding effect on sources
located in the United States. The U.S. Congress has not passed legislation to
reduce emissions of greenhouse gases and the future prospects for any such
legislation are uncertain, but the EPA has existing authority under the Clean
Air Act to regulate greenhouse gas emissions from stationary sources. Several
states have passed laws, adopted regulations or undertaken regulatory
initiatives to reduce the emission of greenhouse gases, primarily through the
planned development of greenhouse gas emission inventories and/or regional
greenhouse gas cap and trade programs. Oklahoma, Arkansas and Texas are not
among them. If legislation or regulations are passed at the Federal or state
levels in the future requiring mandatory reductions of carbon dioxide and other
greenhouse gases on the Company's facilities, this could result in significant
additional compliance costs that would affect the Company's future financial
position, results of operations and cash flows if such costs are not recovered
through regulated rates.
Following from the Supreme Court's interpretation of the Clean Air Act's
applicability to greenhouse gases in Massachusetts v. EPA, the EPA has proposed
regulations for new power plants. In 2010, the EPA also issued a final rule that
makes certain existing sources subject to permitting requirements for greenhouse
gas emissions. This rule requires sources that emit greater than 100,000 tons
per year of greenhouse gases to obtain a permit for those emissions, even if
they are not otherwise required to obtain a new or modified permit. Such sources
that undergo construction or modification may have to install best available
control technology to control greenhouse gas emissions. Although these rules
currently do not have a material impact
77
--------------------------------------------------------------------------------on the Company's existing facilities, they ultimately could result in
significant changes to the Company's operations, significant capital
expenditures by the Company and a significant increase in the Company's cost of
conducting business.
In 2009, the EPA adopted a comprehensive national system for reporting emissions
of carbon dioxide and other greenhouse gases produced by major sources in the
United States. The reporting requirements apply to large direct emitters of
greenhouse gases with emissions equal to or greater than a threshold of 25,000
metric tons per year, which includes certain OG&E and Enogex facilities. OG&E
also reports quarterly its carbon dioxide emissions from generating units
subject to the Federal Acid Rain Program. OG&E and Enogex have submitted the
reports required by the applicable reporting rules.
The Company is continuing to review and evaluate available options for reducing,
avoiding, offsetting or sequestering its greenhouse gas emissions. OG&E is a
partner in the EPA Sulfur Hexafluoride Voluntary Reduction Program. Enogex is a
partner in the EPA Natural Gas STAR Program, a voluntary program to reduce
methane emissions.
The Company also seeks to utilize renewable energy sources that do not emit
greenhouse gases. OG&E's service territory is in central Oklahoma and borders
one of the nation's best wind resource areas. The Company has leveraged its
advantageous geographic position to develop renewable energy resources and
transmission to deliver the renewable energy. The SPP has begun to authorize the
construction of transmission lines capable of bringing renewable energy out of
the wind resource area in western Oklahoma, the Texas Panhandle and western
Kansas to load centers by planning for more transmission to be built in the
area. In addition to significantly increasing overall system reliability, these
new transmission resources should provide greater access to additional wind
resources that are currently constrained due to existing transmission delivery
limitations.
Endangered Species
Certain Federal laws, including the Bald and Golden Eagle Protection Act, the
Migratory Bird Treaty Act and the Endangered Species Act, provide special
protection to certain designated species. These laws and any state equivalents
provide for significant civil and criminal penalties for unpermitted activities
that result in harm to or harassment of certain protected animals and plants,
including damage to their habitats. If such species are located in an area in
which the Company conducts operations, or if additional species in those areas
become subject to protection, the Company's operations and development projects,
particularly transmission, wind or pipeline projects, could be restricted or
delayed, or the Company could be required to implement expensive mitigation
measures. The U.S. Fish and Wildlife Service announced a proposed rule to list
the lesser prairie chicken as threatened on November 30, 2012. A final decision
regarding listing is anticipated to be completed by September 30, 2013. Although
the lesser prairie chicken and its habitat are located in potential development
areas of the Company, the impact of a final decision to list this species as
threatened cannot be determined at this time.
Waste
OG&E's and Enogex's operations generate hazardous wastes that are subject to the
Federal Resource Conservation and Recovery Act of 1976 as well as comparable
state laws which impose detailed requirements for the handling, storage,
treatment and disposal of hazardous waste.
For OG&E, these laws impose strict "cradle to grave" requirements on generators
regarding their treatment, storage and disposal of hazardous waste. OG&E
routinely generates small quantities of hazardous waste throughout its system
and occasional larger quantities from periodic power generation related
activities. These wastes are treated, stored and disposed at facilities that are
permitted to manage them.
In June 2010, the EPA proposed new rules under Federal Resource Conservation and
Recovery Act of 1976 that could alter the classification of OG&E's coal-fired
power plants as conditionally exempt hazardous waste generators and make the
management of coal ash more costly. The extent to which the EPA intends to
regulate coal ash is uncertain due to the fact that the new rules propose to
regulate coal ash as a hazardous waste or as a nonhazardous solid waste. In
November 2010, OG&E submitted written comments opposing the regulation of coal
ash as a hazardous waste while supporting its regulation as a nonhazardous
waste. The EPA continues to consider numerous comments received on the proposal
and has stated that no definitive timetable for issuing a final rule regarding
the regulation of coal ash can be provided.
The Company has sought and will continue to seek pollution prevention
opportunities and to evaluate the effectiveness of its waste reduction, reuse
and recycling efforts. In 2012, the Company obtained refunds of $6.4 million
from the recycling of scrap metal, salvaged transformers and used transformer
oil. This figure does not include the additional savings gained through the
reduction and/or avoidance of disposal costs and the reduction in material
purchases due to the reuse of existing materials. Similar savings are
anticipated in future years.
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For Enogex, the Federal Resource Conservation and Recovery Act of 1976 currently
exempts many natural gas gathering and field processing wastes from
classification as hazardous waste. However, these oil and gas exploration and
production wastes may still be regulated under state law or the less stringent
solid waste requirements of the Federal Resource Conservation and Recovery Act
of 1976. The transportation of natural gas in pipelines may also generate some
hazardous wastes that are subject to the Federal Resource Conservation and
Recovery Act of 1976 or comparable state law requirements.
Water
OG&E's and Enogex's operations are subject to the Federal Clean Water Act, and
analogous state laws and regulations. These laws and regulations impose detailed
requirements and strict controls regarding the discharge of pollutants into
state and Federal waters. The discharge of pollutants, including discharges
resulting from a spill or leak, is prohibited unless authorized by a permit or
other agency approval. The Federal Clean Water Act and regulations implemented
thereunder also prohibit discharges of dredged and fill material in wetlands and
other waters of the United States unless authorized by an appropriately issued
permit. Existing cooling water intake structures are regulated under the Federal
Clean Water Act to minimize their impact on the environment.
With respect to cooling water intake structures, Section 316(b) of the Federal
Clean Water Act requires that their location, design, construction and capacity
reflect the best available technology for minimizing their adverse environmental
impact via the impingement and entrainment of aquatic organisms. In March 2011,
the EPA proposed rules to implement Section 316(b). On August 18, 2011, OG&E
filed comments with the EPA on the proposed rules. In June 2012, the EPA
published a Notice of Data Availability requesting additional comments on a
number of impingement mortality-related issues based on new information received
during the initial public comment period. On July 11, 2012, OG&E filed comments
regarding the Notice of Data Availability. In July 2012, the EPA entered into a
settlement agreement in a pending litigation matter, which extended the deadline
by which the proposed rules will be finalized to June 2013. In the interim, the
state of Oklahoma requires OG&E to implement best management practices related
to the operation and maintenance of its existing cooling water intake structures
as a condition of renewing its discharge permits. Once the EPA promulgates the
final rules, OG&E may incur additional capital and/or operating costs to comply
with them. The costs of complying with the final water intake standards are not
currently determinable, but could be significant.
Site Remediation
The Comprehensive Environmental Response, Compensation and Liability Act of 1980
and comparable state laws impose liability, without regard to the legality of
the original conduct, on certain classes of persons responsible for the release
of hazardous substances into the environment. Because OG&E and Enogex utilize
various products and generate wastes that are considered hazardous substances
for purposes of the Comprehensive Environmental Response, Compensation and
Liability Act of 1980, OG&E and Enogex could be subject to liability for the
costs of cleaning up and restoring sites where those substances have been
released to the environment. At this time, it is not anticipated that any
associated liability will cause a significant impact to OG&E or Enogex.
For a further discussion regarding contingencies relating to environmental laws
and regulations, see Note 16 of Notes to Consolidated Financial Statements.
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