EAST KENTUCKY POWER COOPERATIVE ANNUAL … Kentucky Power Cooperative Annual...37 Report of...

2014EAST KENTUCKY POWER COOPERATIVE ANNUAL REPORT

STRENGTH in numbers

Table of Contents

2 2014: Highlights

4 Member Systems and EKPC Generation Capacity

5 A Message from the CEO and the Chairman

9 2014: Year in Review

27 EKPC Board, Officers and Member CEOs

29 Board Committees

31 Executive Staff

32 Financial and Operational Leadership

33 Financial Highlights and Charts

37 Report of Management

38 Independent Auditors’ Report and Financial Statements

1 EKPC 2014 Annual Report

2014 2013 Increase/(Decrease)Operating Revenue $952,771 $903,243 5.5Operating Expenses $782,827 $728,046 7.5Net Margin $64,845 $68,903 (5.9)Members’ Equities $482,553 $428,742 12.6Equity Ratio (%) 14.2 12.7 11.8

2014 2013 Increase/(Decrease)Sales to Member Cooperatives (MWh) 13,119,594 12,648,483 3.7Member Revenue Per kWh Sold (mills/kWh) 69.15 69.74 (0.8)Cost of Owned Generation (mills/kWh) 57.00 57.39 (0.7)System Peak Demand (MW) Winter Season 3,425 2,597 31.9 Summer Season 2,192 2,199 (0.3)Net Generation (MWh) 10,462,583 10,127,954 3.3

%

%

2014: Highlights

Power Plant Capacityby MW

1%

6%70%

23%Landfill gas

Natural gas -LMS 100s

Natural gasconventional peakers

Coal

Sources of Electricityby MWh

23%

1%

2% 71%Landfill gas

Natural gas

Hydro/purchases

Coal

Other purchases

3%

Customer Classesby member sales revenue

16% 66%

18%Small Commercial

Industrial

Residential

Financial (Dollars in Thousands)

Operational

* Includes steam sales

** Data reported represents seasonal peak achieved during current calendar year (1/29/14 and 1/22/13)

Note: Pie chart figures are rounded.

**

**

EKPC 2014 Annual Report 2

Located in the heart of the Bluegrass state, East Kentucky Power Cooperative is a not-for-profit generation and transmission (G&T) electric utility with headquarters in Winchester, Ky. Our cooperative has a vital mission: to safely generate and deliver affordable, reliable electric power to 16 owner-member cooperatives serving more than one million Kentuckians.

Together, with our 16 owner-members, we’re known as Kentucky’s Touchstone Energy Cooperatives. The member co-ops distribute energy to 527,175 Kentucky homes, farms, businesses and industries across 87 counties. We’re leaders in energy efficiency and environmental stewardship. And we’re committed to providing power to improve the lives of people in Kentucky.

2014 at a glance

Total Energy Sales

(GWh)

13.9

Energy Sales to

Members

(GWh)

13.1

Total Operating

Revenue

($ millions)

952.8

Assets

($ billions)

3.4

Energy Sales to

Non-members

(GWh)

0.8

Member Consumers

527,175

Net Margin

($ millions)

64.8

Average Wholesale

Rate to Members

$/MWh

69.2

Number of

Member Systems

16

STRENGTH in numbers


Sixteen distribution cooperatives, which are called the member systems, own EKPC. The 16 co-ops include: Big Sandy RECC Blue Grass Energy Cooperative Clark Energy Cooperative Cumberland Valley Electric Farmers RECC Fleming-Mason Energy Cooperative Grayson RECC Inter-County Energy

Jackson Energy Cooperative Licking Valley RECC Nolin RECC Owen Electric Cooperative Salt River Electric Cooperative Shelby Energy Cooperative South Kentucky RECC Taylor County RECC

shows system-wide service area

1 Spurlock 1,346 net MW

2 Dale 195 net MW

3 Smith Summer Combustion 784 net MW Turbine Winter Units 1,032 net MW

4 Cooper 341 net MW

Landfill Gas Plants

5 Bavarian 3.0 net MW

6 Laurel Ridge 3.0 net MW

7 Green Valley 2.3 net MW

8 Pearl Hollow 2.3 net MW

9 Pendleton 3.0 net MW

10 Mason 0.8 net MW*

SoutheasternPower Adm. (SEPA),hydro power 170 MW

* Mason will be officially closed in 2015

East Kentucky Power Cooperative Generation

Member Populations

Served (millions)

1.1

Member Peak

Demand (MW)

3,425

Generating Capacity

Coal (MW)

1,882

Generating Capacity

Natural Gas/Oil (MW)

1,032

Renewable Energy

(includes SEPA)

(MW)

184.4

Miles of

Transmission Lines

2,835

Employees

666

EKPC headquarters


1

23

4

5

8

9

6

710

Successful businesses continuously improve and develop their people, make their processes more efficient and strengthen their bottom line.

During 2014, East Kentucky Power Cooperative’s (EKPC) Board and management did that by consistently executing a strategic plan that improved our finances and operations, while constantly focusing on good stewardship of resources.

Safety culture continues to improve

Throughout the year, we maintained focus upon our highest priority – safety.

In 2014, we conducted an independent survey of employees to guide our ongoing journey to a culture of safety, and we’re thrilled to report that 100 percent of our employees participated.

The survey demonstrated how engaged EKPC employees are in safety, and reinforced our belief that we’ve made tremendous progress in advancing toward a culture of zero-injury incidents. Although a small number of employees may not have embraced our journey, the survey results confirmed that the vast majority of employees recognize – and appreciate − significant improvements in safety programs, leadership and processes. Best of all, they feel empowered to take actions as needed to work safely.

Financial markets recognize our success story

We are pleased to report that the strong financial performance of recent years continued during 2014, and the results once again demonstrated the success of the Board’s comprehensive strategic planning process.

EKPC posted a net margin of $64.8 million on total revenues of $952.8 million for the year ended Dec. 31, 2014. As a result of the hard work of the Board, management and employees, we finished the year strong with 14.2 percent equity, up from a low of 6.8 percent in 2008.

In the fall, Standard & Poor’s (S&P) announced a rare, double-notch upgrade of EKPC’s issuer credit rating to “A-” with a stable outlook. Also in the fall, Fitch Ratings affirmed EKPC’s credit rating at “BBB+” and revised EKPC’s rating outlook to “positive,” a move up from “stable.”

Operations thrive in PJM

One of the year’s biggest challenges occurred when January’s

arctic weather produced Kentucky’s coldest temperatures in more than a decade, spurring two all-time winter peaks. And the extreme cold continued well into March.

Having integrated into PJM, the world’s largest centrally dispatched power grid, in 2013, we were prepared for this challenge. During the big chill, EKPC met our owner-members’ needs through our outstanding operation of our generating units and by securing critical capacity through PJM.

PJM integration provided many financial and operational benefits throughout the year that far exceeded expectations. Participation in the PJM marketplace strongly supports our mission: to provide reliable and affordable energy to our 16 owner-member cooperatives.

In support of the reliability goal, EKPC invested $20.9 million in 2014 to upgrade or build new transmission and distribution substations and transmission lines. We plan to prudently invest in these facilities over the next 10 years.

Preparing for regulatory challenges ahead

Throughout 2014, we worked diligently to meet the complex challenges of compliance with ever-tightening federal environmental regulations.

Like utilities nationwide, in 2014 we announced plans to deactivate our oldest coal-fueled plant, Dale Station. To prepare for the loss of this plant by April 2016, we issued a request for proposals for up to 200 megawatts of additional generation, and we are continuing to analyze the best way to hedge future load growth while complying with federal rules.

One of our greatest successes for future compliance occurred during 2014 when the Kentucky Public Service Commission (PSC) approved our application to retrofit Cooper Station Unit #1, and tie it into the new air quality control system for Unit #2. This enables Cooper Unit #1 to comply with emissions regulations and remain operational at a very low cost.

Devastating impacts of federal rules on people

At the close of 2014, we again expressed deep concerns to Washington, D.C. about the devastating impacts of environmental regulations that continue to raise monthly bills for those who can least afford this burden, especially the elderly, thousands of unemployed coal miners and workers from related industries, and

A Message from the CEO and the Chairman

STRENGTH in numbers


Anthony CampbellPresident and CEO

Paul HawkinsChairman of the Board

citizens across the service territory who are already struggling to make ends meet.

We are deeply concerned that current and proposed EPA rules will force dependence on natural gas when gas may not have adequate transportation infrastructure. There are also questions about natural gas price volatility, grid reliability and national security if the EPA forces natural gas to become America’s only electric generating fuel for new plants.

We will continue to work tirelessly to help end-use members through renewed emphasis on economic development programs,

as well as energy efficiency and demand-side management programs to help lower bills while improving comfort in their homes.

Major challenges still lie ahead, but we have the people we need to meet the challenges, and we are prepared to do whatever is necessary to stay strong. By working in unity with our owner-members and doing everything we can to help the 1.1 million people that they serve, we can overcome any obstacles that come our way. That is true strength in numbers.


President and CEO Anthony Campbell (left) with Chairman of the Board Paul Hawkins.

STRENGTH in numbers



The 16 cooperatives distribute electric power across 87 Kentucky counties.

1MILLIONpeople served by 16 owner-member cooperatives delivering aff ordable, reliable energy

STRENGTH in numbers


People and planning

Safety culture continues to develop

With the support of the EKPC Central Safety Committee, the members of five process

improvement teams, safety committees at each plant, service center and our headquarters

location, and the participation of our workforce, EKPC has established that nothing

is more important than employees going home as healthy as they were when they

arrived at work.

An independent survey by DuPont Sustainable Solutions in 2014 confirmed that

employees feel that the Target Zero safety program has been one of the most positively

influential programs the cooperative has ever implemented. Although the program

will continue to improve, the survey confirmed there is a heightened awareness of the

impact of safety across the entire organization.

Better still, the survey showed an 18-point improvement over the previous survey in

DuPont’s Bradley Curve, a measure of the development of an effective safety culture,

and demonstrates a proactive approach to safety.

In January 2014, EKPC held its second company-wide Safety Week in which CEO Tony

Campbell named four employees as Safety All-Stars.

Among many successes throughout the year, EKPC standardized job briefings,

improved the safety training of contractors, developed a new automated incident

investigation process, trained all front-line supervisors to conduct job hazard analyses,

overhauled the corporate Safe Work Manual and defined Cardinal Safety Rules.

Employees also performed more than 4,000 safety observations during the year, resulting

in heightened safety awareness, better communications, and numerous process and

condition improvements.

Target Zero makes safetyEKPC’s top priority

EKPC set an ambitious goal in 2011 with the launch of Target Zero, a campaign seeking to achieve no accidents at work or at home. Since then, there have been thousands of safety observations, safety art contests for kids, family safety fairs and banners with safety messages posted at all locations.

2014: Year in Review

THOUSAND safety observations done to heighten awareness and improve communication

4EKPC 2014 Annual Report 10


STRENGTH in numbers

64.8 MILLION dollar net margin in 2014

builds capital resources


Financial markets recognized EKPC’s success in 2014. Standard and Poor’s upgraded EKPC’s issuer credit rating to “A-“ with a stable outlook. Fitch affirmed EKPC’s credit rating at “BBB+” and revised the rating outlook to positive.

STRENGTH in numbers


Operations

First full year in PJM marketplace exceeds expectations

EKPC’s first full year of participation in the PJM marketplace provided critical capacity

and positive economic benefits throughout the year.

Valley Forge, Pa.-based PJM directs the orderly flow of bulk power across 13 states and

the District of Columbia, and manages the generation and transmission system across

this market like an air traffic controller directing the movement of aircraft.

PJM helped EKPC to manage weather impacts across the system by providing virtually

unlimited capability to import power, and PJM also provided opportunities for sales of

excess power generation.

PJM enabled EKPC to meet record system loads and manage the record-setting cold

during the polar vortex that gripped America in 2014. Plant staff worked hard throughout

the year to reduce dispatch costs through the work process optimization program,

sourcing lower cost fuel for Cooper Station and reducing consumption of environmental

additives, among other successes.

Acting as a neutral, independent party, PJM operates a competitive wholesale electricity market and manages the high-voltage electricity grid to ensure reliability for the people served by EKPC’s owner-member co-ops and more than 61 million people.

Chris Adams, Supervisor of Power Delivery Planning, monitors the system in EKPC’s headquarters Control Room.


MEGAWATT winter season system peak reached Jan. 29, 2014

3,425


Projects keep generation fleet in top condition

After the record-cold winter, employees set their sights on spring maintenance outages

at Spurlock and Cooper Stations, and on a future major retrofit of Cooper Unit #1.

In early spring, Spurlock Station employees completed a major outage on Unit #3,

which is named the Gilbert Generating Unit in honor of the late Board Chairman E.A.

“Ned” Gilbert. During the outage, workers installed new equipment and performed

major ductwork upgrades. Workers also completed a replacement of the Economizer

Hoppers on Spurlock Unit #2.

Cooper Station employees also performed a major spring outage, installing scaffolding

12 stories high on Unit #2 from the basement to the top of the boiler. They did ultra-

sonic testing of the tubes and replaced 3,200 feet of re-heat tubing.

Operating practices, unit generating performance, and operating and maintenance

costs were benchmarked in an independent study conducted at Spurlock Station, while

similar studies were launched at both Cooper and Smith Stations. Results continue to

demonstrate that the EKPC fleet performs at or near the top of its class in comparison

to its peers, while identifying opportunities to enhance performance further.

Retrofit of Cooper Unit #1 approved

In February, the Kentucky PSC approved EKPC’s application for a Certificate of Public

Convenience and Necessity to retrofit Cooper Unit #1.

The $15 million project will bring the unit into compliance with mandated EPA

regulations and meet the unit’s regulatory deadline of April 2016.

The PSC noted that the retrofit of Unit #1 was the lowest-cost option available of

the 116 proposals that EKPC previously analyzed for additional power supply.

The PSC approved EKPC’s plans to recover the cost of the project through the

environmental surcharge.

A Spurlock Station employee works during the spring 2014 outage to keep the generating units in top condition.

STRENGTH in numbers



FEET of re-heat tubing were replaced on Cooper Station Unit #2 during spring maintenance, along with a complete assessment of the boiler

3,200


STRENGTH in numbers

MILLION dollars invested in 2014 to better ensure reliable delivery of energy

20.9


PJM Interconnection is the world’s largest centrally dispatched grid. PJM has provided EKPC with ready access to market energy and optimized the efficiency of EKPC’s generating units to hedge the system and improve reliability.

STRENGTH in numbers


System protection and reliability

Compliance with required electric reliability standards is a critical part of daily work at

EKPC. In 2014, SERC, a non-profit corporation that works to improve system reliability,

conducted a spot check of EKPC’s compliance with Critical Infrastructure Protection

standards. SERC found no issues with EKPC’s operations, and none have been detected

during rigorous internal reviews.

To ensure that EKPC does everything possible to protect the electric grid, in 2014

employees completed a 30-year work plan to enhance the transmission and delivery

system.

During 2014, Power Delivery & System Operations completed one new green-field

substation, one substation addition, two substation rebuilds and modifications or

upgrades to 15 existing substations. In addition to increased right-of-way vegetation

management, EKPC also completed four new line segments, three line rebuilds and

seven other line-construction projects, along with rebuilds of 100 oil-circuit reclosers.

These upgrades will benefit members by helping ensure reliable service.

EKPC’s Heavy Equipment Team works daily to ensure reliable delivery of power.

Anthony Ballard helps install new equipment at a substation.


14.2PERCENT EQUITYat Dec. 31, 2014 demonstrates fi nancial strength

STRENGTH in numbers


Energy efficiency and the environment

Thousands of energy audits completed

For decades, EKPC and its 16 owner-member cooperatives have proactively helped

end-use members to identify opportunities to improve the energy efficiency of their

homes and businesses. Twenty-nine energy advisors work across the entire service

territory to help people save energy.

In 2014, these professionals conducted nearly 4,000 energy audits to help people

improve the energy efficiency of their homes.

Since 2005, EKPC’s portfolio of programs has achieved average annual energy

reductions of 80 million kilowatt hours and average annual peak reductions of

almost 79 megawatts.

Direct load control continues to grow

EKPC’s SimpleSaver program helps the system to meet peak demand when electric

use is at its highest. By installing remote switches on air conditioners and water heaters,

the SimpleSaver program enables EKPC to manage these units for short periods to

reduce demand and costs during peaks.

In 2014, the SimpleSaver program installed switches on more than 6,358 air conditioners

and water heaters, providing 4.78 additional megawatts of load reduction in summers

and 1.31 megawatts during winters.

New programs launched

During 2014, EKPC developed the following new programs:

• Appliance Recycling Program – Free removal of old refrigerators and freezers that use excessive energy with a $50 incentive.

• Appliance Rebates – Incentives to buy ENERGY STAR® appliances.

• BillingInsights – An online link provides direct access to monthly billing information, allowing instant energy-use monitoring.

• ENERGY STAR® Manufactured Home Program – Pays manufacturers to upgrade members to energy-efficient models.

David Berry checks a SimpleSaver switch. Since the 1970s, EKPC and the owner-members have been pioneers in energy efficiency and DSM programs, especially with SimpleSaver program that puts switches on air conditioners and water heaters.


THOUSANDhome energy audits completed to help members save 4

STRENGTH in numbers


Team proactively studying EPA greenhouse gas rules

Following the June release of 1,700-plus pages of proposed EPA regulations governing

the release of greenhouse gases from existing power plants, a team of employees

proactively evaluated numerous compliance strategies and prepared official comments

that were submitted to the EPA in the fall.

EPA established proposed state-specific targets designed to bring about a 30 percent

overall reduction in CO2 emissions (from 2005 levels) by 2030. EPA also designated

building blocks to reduce carbon that include improving coal plant efficiency, shifting

generation from coal to natural gas combined cycle units, shifting generation to low- or

zero-carbon generation, and increasing energy efficiency and demand-side management

programs. Additional options to dilute CO2 emissions include retiring high CO2-emitting

units and increasing the use of renewable energy.

At the close of the year, EPA finalized the Coal Combustion Residual “Ash Rule” that will

change the way our industry handles, manages and disposes of ash as a result of burning

coal. A cross-divisional team vetted the rule and the potential impacts and considered

the lowest-cost methods of compliance. EPA continues to finalize rules that cost our

owner-member cooperatives money.

Lastly, the Courts and EPA came to an agreement to implement the Cross State Air

Pollution rule (CSAPR) with little notification. The rule became effective Jan. 1, 2015

for Phase I, and Phase II will begin January 1, 2017. EKPC followed this rule closely and

made strategic plans in anticipation of the Courts’ decision. Scrubbing Cooper Unit #1

placed EKPC in compliance with CSAPR and mitigated costs to the owner-members.

Bill Clouse of Cooper Station conducts water quality testing at the plant.

Economic development attracts jobs and investments

In 2014, EKPC’s economic development team supported the economic interests of

owner-member cooperatives by assisting in the retention, expansion and recruitment

of industries that employed more than 2,000 people.

In addition, the Kentucky PSC approved an economic development rider to assist

Kentucky’s Touchstone Energy Cooperatives in attracting new jobs and investments to

the state. EKPC partnered with the Commonwealth of Kentucky and leading economic

development organizations to market service territories through the internet, video

and advertisements in state and national publications.

In 2014, EKPC and the owner-member cooperatives formed a partnership with

Statebook International, an online marketplace that businesses can use to research

every community across the 87-county service territory. EKPC added new staff to

build the economic development capabilities of the system, and participated in many

recruiting and retention efforts within the state and across the nation.

Staff also took on leadership roles at Shaping Our Appalachian Region (SOAR), a

partnership of federal, state and private businesses that is working to improve Eastern

Kentucky’s economy. SOAR is helping to deliver a critical fiber backbone, improving

health care, supporting the extension of the Mountain Parkway and much more to

bring new jobs and investments to the region.

Rodney Hitch (standing), Manager of Economic Development, works with Brad Thomas, Associate Manager of Economic Development. Working with a team of co-op employees, they helped to retain or develop 2,000 jobs in 2014 to improve the quality of lives in areas served by the 16 owner-member cooperatives.


Tobin Pospisil, left, former President of Gallatin Steel, talks to Mark Stallons, President and CEO of Owen Electric Cooperative, an owner-member of EKPC.

STRENGTH in numbers


Focus on financial strength, flexibility and affordability

With its 2014 net margin of $64.8 million, EKPC easily surpassed its minimum targeted

Times Interest Earned Ratio (TIER), Margins for Interest (MFI) and Debt Service Coverage

(DSC) metrics. This enabled EKPC to increase its equity level to 14.2 percent on its path

to a target 15 percent equity level in 2015.

Based in part on its recent strong financial performance, rating agencies increased

EKPC’s debt ratings in 2014, which triggered lower interest costs for EKPC’s debt.

Additionally, EKPC tapped the Private Placement debt market for $200 million in

2014, demonstrating the flexibility to obtain financing outside of its traditional lenders.

EKPC highlighted its commitment to keeping rates affordable to its owner-member

cooperatives by managing its costs such that it avoided seeking a base rate increase

for the 4th year in a row despite numerous cost pressures such as new facilities and

environmental mandates.

Co-ops sponsor veterans, Special Olympics and students

In 2014, EKPC and the 16 owner-member cooperatives sponsored programs that

supported veterans, students and Special Olympians.

The 2014 Touchstone Energy All “A” Classic provided college scholarships to 70 seniors

from Kentucky’s smallest high schools. It is best known for its outstanding basketball

tournaments each January and February across the entire state, but it also included

exciting competitions in art, cheerleading, baseball, softball, volleyball and golf.

During the summer, Kentucky’s Touchstone Energy Cooperatives were platinum sponsors

of the Special Olympics State Summer Games at Eastern Kentucky University in Richmond.

In September, the cooperatives joined with the Bluegrass Chapter of the Honor Flight

Network to sponsor an Honor Flight for 22 veterans from Kentucky who served during

World War II, the Korean War or the Vietnam War.

EKPC and Kentucky’s Touchstone Energy Cooperatives show commitment to local communities by sponsoring an annual Honor Flight for World War II and Korean War veterans, along with Kentucky Special Olympics and the Touchstone Energy All “A” Classic.


NET MEGAWATTSof generation capacity provides people across 87 counties with aff ordable, reliable power

3,098

EKPC Board, Offi cers and Member CEOs

Standing from left are:

Carol Fraley, President and CEO, Grayson RECC; Mark Stallons, President and CEO, Owen Electric Cooperative; Alan Ahrman, Director (Owen Electric Cooperative); Landis Cornett, Director (Jackson Energy); Jimmy Longmire, Director (Salt River Electric); Bill Prather, President and CEO, Farmers RECC; Elbert Hampton, Director (Cumberland Valley Electric); Joe Spalding, Director (Inter-County Energy); Mike McNalley, Executive Vice President and Chief Financial Offi cer, EKPC; David Estepp, President and CEO, Big Sandy RECC; Don Mosier, Executive Vice President and Chief Operating Offi cer, EKPC; Kerry Howard, General Manager and CEO, Licking Valley RECC; Tony Campbell, President and CEO, EKPC; Jody Hughes, Director (Blue Grass Energy); Paul Hawkins, Board Chairman (Farmers RECC); Mike Williams, President and CEO, Blue Grass Energy; Jim Jacobus, President and CEO, Inter-County Energy; Chris Brewer, President and CEO, Clark Energy; Kenneth Arrington, Director (Grayson RECC); Raymond Rucker, Director (Taylor County RECC); Debbie Martin, President and CEO, Shelby Energy; and Carol Wright, President and CEO, Jackson Energy;

STRENGTH in numbers


STRENGTH in numbers

Seated from left are:

Allen Anderson, President and CEO, South Kentucky RECC; Tim Eldridge, Director (Fleming-Mason Energy Cooperative); Joni Hazelrigg, President and CEO, Fleming-Mason Energy Cooperative; Mike Adams, Director (Licking Valley RECC); A.L. Rosenberger, Board Secretary-Treasurer (Nolin RECC); Kelly Shepherd,* Director (Big Sandy RECC); Wayne Stratton, Director (Shelby Energy); Lee Coffee, Director (South Kentucky RECC); and Bill Shearer, Director (Clark Energy). Not in photo: Barry Myers, Manager, Taylor County RECC; Ted Hampton, President and CEO, Cumberland Valley Electric; Mickey Miller, President and CEO, Nolin RECC; Wade May, Vice Chairman (Big Sandy RECC); Larry Hicks, President and CEO, Salt River Electric.

* Kelly Shepherd was seated in March 2015 to replace Wade May who retired.


From left are: Michelle Carpenter (Staff Liaison), Chris Brewer, Kelly Shepherd,* Carol Wright, Alan Ahrman, Jimmy Longmire, Raymond Rucker, Joe Spalding (Chairman), Barry Myers and Debbie Martin. Not in photo: Allen Anderson.

* Kelly Shepherd was seated in March 2015 to replace Wade May who retired.

Note: Bold names are voting committee members

From left are: Mike McNalley (Staff Liaison), Tony Campbell, Mike Adams, Patrick Sterling (Senior Director, Risk & People Administration, Texas Roadhouse), Wayne Stratton (Chairman), Elbert Hampton, Bill Prather, Jody Hughes, Mike Steffes (CEO, ACES), Paul Hawkins and Carol Fraley.


Assists the Board in fulfilling its governance oversight by: ensuring that the Board meets its fiduciary duties, upholds governance guiding principles and is fully engaged; maintaining the integrity of Board governance; developing, updating and recommending corporate governance principles and policies; and monitoring compliance with those principles and policies.

Governance Committee

Assists the Board in fulfilling its risk oversight responsibilities by reviewing enterprise-wide risks, reviewing risk tolerances and recommending risk-management policies to the Board.

Board Risk Oversight Committee

STRENGTH in numbers


From left are: Don Mosier (Staff Liaison), Ted Hampton, Landis Cornett (Chairman), Kenneth Arrington, Lee Coffee, Joni Hazelrigg, Kerry Howard, A.L. Rosenberger, Jim Jacobus, Mike Williams, Bill Shearer and Tim Eldridge. Not in photo: Mark Stallons.


From left are: Lesli Yates (Staff Liaison), Bill Shearer (Chairman), Tim Eldridge, David Estepp, Joe Spalding, Mike Adams and Wayne Stratton. Not in photo: Mickey Miller.


Serves as a catalyst of business strategies, monitors the development and implementation of those strategies, while working with management to develop Board focus on issues that will further strategic planning and execution of those plans.

Strategic Issues Committee

Assists the Board in performing oversight of: the quality and integrity of financial statements; compliance with legal and regulatory requirements related to finances; the independent auditor’s qualifications and independence; the performance of EKPC’s internal audit function and the oversight of the independent auditors; fraud detection and related procedures; and conflict-of-interest policies.

Audit Committee


EKPC Executive Staff

Back row, from left, are: Steve McClure, Vice President of Human Resources and Support Services; Barry Mayfi eld, Vice President of Strategic Planning and External Affairs; David Smart, General Counsel; David Crews, Senior Vice President of Power Supply; Craig Johnson, Senior Vice President of Power Production; Mike McNalley, Executive Vice President and CFO; Tony Campbell, President and CEO; Don Mosier, Executive Vice President and COO.

Front row, from left, are: Susan Brooks, Treasurer and Director of Finance; Denver York, Senior Vice President of Power Delivery and System Operations; Jerry Purvis, Director of Environmental Affairs; and Lesli Yates, Internal Auditor.

STRENGTH in numbers


EKPC Financial Leadership

Clockwise, from left, are: Susan Brooks, Treasurer and Director of Finance; Narmada Nanjundan, Director of Risk Management; Mike McNalley, Executive Vice President and CFO; Robin Hayes, Manager of Performance and Improvement; and Michelle Carpenter, Controller.

EKPC Operational Leadership

Clockwise, from left, are: Denver York, Senior Vice President of Power Delivery and System Operations; David Crews, Senior Vice President of Power Supply; Don Mosier, Executive Vice President and COO; Jerry Purvis, Director of Environmental Affairs; and Craig Johnson, Senior Vice President of Power Production.


2014: Financial Highlights

Strong performance improves financial metrics

During 2014, EKPC achieved a net margin of $64.8 million,

which exceeded budget by $12.4 million. This margin

improved EKPC’s equity-to-assets ratio from 12.7 percent

in 2013 to 14.2 percent, keeping EKPC on track to meet its

Strategic Plan objective set in 2011 of 15 percent equity in 2015.

EKPC’s operating revenues for the year ended December

31, 2014, increased $49.5 million from the prior year. This was

attributed to a net increase in member sales of $25.1 million

due to more favorable weather conditions than the prior

year, as well as an increase in off-system sales of $22.4 million.

Member sales were reduced in 2014 by $9.8 million due to a

Kentucky Public Service Commission (PSC) order disallowing

the recovery of certain purchased power costs through the

fuel adjustment clause. This matter has been approved for

rehearing by the Commission in 2015.

Production operating expenses for the year ended

December 31, 2014 increased $50.7 million, mainly to

support the increase in sales. These expenses, which are

comprised of fuel, operation and maintenance expenses,

and purchased power, are grouped together for comparative

purposes given that decisions to generate energy or purchase

energy on the open market are based on reliability constraints

and the most economic resources available within the PJM

market. Purchased power costs for the comparative period

increased $40.0 million, while fuel costs increased only $4.5

million due largely to the favorable market prices in comparison

to units available to serve load.

Rating agencies upgrade credit rating and outlook

In 2014, two ratings agencies recognized EKPC’s improvements

in financial performance. In the fall, Standard & Poor’s

(S&P) announced a rare, double-notch upgrade of EKPC’s

issuer credit rating to “A-” with a stable outlook. Also in the

fall, Fitch Ratings affirmed EKPC’s credit rating at “BBB+”

and revised EKPC’s rating outlook to “positive,” a move up

from “stable.”

Private placement debt transaction completed

Improved financial performance and positive credit ratings

enabled EKPC to successfully tap the Private Placement

debt market, demonstrating EKPC’s ability to obtain

financing outside of its traditional lenders. EKPC entered

into a Bond Purchase Agreement for $200 million 4.61%

first mortgage bonds, due in 2044. The proceeds from

this transaction were used to pay down a portion of the

outstanding borrowings on EKPC’s unsecured syndicated

credit facility.

Favorable regulatory approvals

In early 2015, the PSC approved EKPC’s request to recognize

depreciation and accretion expenses related to its asbestos

abatement and ash disposal asset retirement obligations

(ARO) as regulatory assets for 2014 and all subsequent years

with the exception of a portion of one ARO associated with

ash transfer costs at Dale Station. This approval enables

EKPC to defer these expenses until retirement projects

are authorized for recovery by the PSC, thereby matching

revenues and expenses. In a separate proceeding, the PSC

approved recovery of the costs that will settle the Dale

Station ash disposal ARO through the environmental

surcharge mechanism.

STRENGTH in numbers


2014 2013 2012 2011 2010

Net Margin - in thousands $64,845 $68,903 $52,836 $55,896 $32,800

TIER 1.56 1.61 1.46 1.48 1.28

DSC 1.30 1.34 1.22 1.20 1.12

Fuel Expense - in thousands 297,399 $292,918 $310,642 $364,444 $342,071

Capital Expenditures - in thousands

Generation $41,793 $25,105 $84,216 $135,938 $105,818

Transmission & Distribution $20,937 $25,779 $20,681 $34,740 $27,532

General $10,172 $1,851 $958 $1,845 $1,586

Investment in Facilities - in thousands

Original Cost $3,867,127 $3,804,664 $3,737,247 $3,634,367 $3,462,772

Long-Term Debt - in thousands $2,632,276 $2,680,289 $2,656,514 $2,624,168 $2,571,421

Total Assets - in thousands $3,403,556 $3,370,055 $3,278,737 $3,241,917 $3,111,726

Number of Employees - full-time 666 643 664 680 689

Cost of Coal Purchased

$/ton $55.49 $58.01 $60.44 $58.64 $56.15

$/MBtu $2.44 $2.55 $2.65 $2.57 $2.49

Amount of Coal Purchased - tons 4,288,956 4,571,750 4,293,199 5,277,817 5,214,581

Generation - MWh 10,462,583 10,127,954 11,075,566 12,444,859 12,570,249

System Peak Demand - MW

Winter Season * 3,425 2,597 2,597 2,481 2,889

Summer Season 2,192 2,199 2,354 2,388 2,440

Sales to Other Utilities - MWh 805,511 509,140 223,609 704,276 544,218

Member Load Growth - %

Energy 3.72 3.89 (2.64) (4.58) 7.07

Demand 3.23 3.18 (2.99) 0.73 1.73

Load Factor - % 44 56 56 58 52

Miles of Line 2,835 2,816 2,807 2,806 2,797

Installed Capacity - kVA 10,779,247 9,508,311 9,496,311 9,425,511 9,425,511

Distribution Substations 364 363 362 356 351

Five-Year Statistical Summary

* Beginning in 2013, data reported represents seasonal peak achieved during current calendar year (1/29/14 and 1/22/13)


0

10

20

30

40

50

60

70

80

2010 2011 2012

Power Cost to Members Mills/kWh

28.21 29.86

61.45 67.78 68.41

27.07 30.35

6.177.57

28.58

31.04

8.79

2013

69.74

29.67

30.83

9.24

2014

69.15

29.97

30.71

8.47

FuelBasic RateEnvironmental Surcharge

0

2

4

6

8

10

12

14

16

2010 2011 2012 2013

8.0 9.6 11.0 12.7

2014

14.2

Equity Ratio

0.0

0.3

0.6

0.9

1.2

1.5

1.7

2010 2011 2012 2013

TIER

1.28 1.48 1.46 1.61

2014

1.56 0.0

0.3

0.6

0.9

1.2

1.5

2010 2011 2012 2013

DSC

1.12 1.20 1.22 1.34

2014

1.30

0

50

100

150

200

250

300

350

400

450

500

2010 2011 2012 2013

Members’ Equities in Millions

247.7 309.7 359.9 428.7

2014

482.6

2010 2011 2012 2013

Total Assets

3,112 3,242 3,279 3,370

2014

3,4040

500

1,000

1,500

2,000

2,500

3,000

3,500

in Millions

STRENGTH in numbers


0

1

2

3

4

5

2010 2011 2012 2013

Average Interest Rate on Long-Term Debt Year-End

Average %

4.39 4.38 4.16 4.08

2014

4.210

20

40

60

80

100

120

2010 2011 2012 2013

Interest Expense onLong-Term Debt in $Millions

116.3 116.8 114.1 112.3

2014

116.1

0

200

400

600

800

1000

2010 2011 2012 2013

Operating Revenuein $Millions

827.4 877.6 843.1 903.2

2014

952.80

3

6

9

12

15

2010 2011 2012 2013

Energy Sales to MembersMWh in Millions

13.1 12.5 12.2 12.7

2014

13.1

0

500

1,000

1,500

2,000

2,500

3,000

3,500

2010 2011

System Coincident PeakMW

Summer Winter

2,44

0

2,38

8

2,48

1

2012

2,35

4

2,59

7

2013

2,19

9

2,59

7

2014

2,19

2

3,42

5

2,88

9

0

50,000

100,000

150,000

200,000

250,000

2010 2011 2012 2013 2014

Capital Expendituresin $Thousands

25,105

25,779

20,681

34,740

27,532

1,851

958

1,845

1,586

84,216135,938105,818

GenerationTransmission & DistributionGeneral

41,793

20,937

10,172


The accompanying financial statements of East Kentucky Power Cooperative, Inc. were prepared by management, which

is responsible for their integrity and objectivity. The statements were prepared in accordance with accounting principles

generally accepted in the United States of America and include amounts that are based on management’s best judgments and

estimates. The other financial information included in this annual report is consistent with the financial statements.

The cooperative maintains a system of internal controls, including accounting controls and internal auditing. The system

of controls provides for appropriate division of responsibility and the application of policies and procedures that are

consistent with high standards of accounting and administration. The cooperative believes that its system of internal

controls provides reasonable assurance that assets are safeguarded against loss from unauthorized use or disposition

and that financial records are reliable for use in preparing financial statements.

The financial statements have been audited by the cooperative’s independent certified public accountants, Ernst &

Young LLP, whose opinion appears on the next page.

The Board of Directors, through its Audit Committee consisting solely of outside directors and member system CEOs, meets

with Ernst & Young LLP, representatives of management and the internal auditor to review their activities and to

discuss accounting, auditing and financial matters and the carrying out of responsibilities and duties of each group.

Ernst & Young LLP, has full and free access to meet with the Audit Committee to discuss their audit results and

opinions, without management representatives present, to allow for complete independence.

Anthony Campbell Mike McNalley

President and CEO Chief Financial Officer

Report of Management

STRENGTH in numbers


Report of Independent Auditors

The Board of Directors East Kentucky Power Cooperative, Inc.

Report on the Financial Statements

We have audited the accompanying financial statements of East Kentucky Power Cooperative, Inc., which comprise the balance sheets as of December 31, 2014 and 2013, and the related statements of revenues and expenses and comprehensive margin, changes in members’ equities, and cash flows for the years then ended and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States and the standards applicable to financial audits contained in Government Auditing Standards, issued by the Comptroller General of the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

Ernst & Young LLP Suite 2400 400 West Market Street Louisville, KY 40202

Tel: +1 502 585 1400 Fax: +1 502 584 4221 ey.com


We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of East Kentucky Power Cooperative, Inc. as of December 31, 2014 and 2013, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

Other Reporting Required by Government Auditing Standards

In accordance with Government Auditing Standards, we also have issued our report dated March 31, 2015 on our consideration of the East Kentucky Power Cooperatives, Inc.’s internal control over financial reporting and on our tests of its compliance with certain provisions of laws, regulations, contracts, and grant agreements and other matters. The purpose of that report is to describe the scope of our testing of internal control over financial reporting and compliance and the results of that testing, and not to provide an opinion on the internal control over financial reporting or on compliance. That report is an integral part of an audit performed in accordance with Government Auditing Standards in considering East Kentucky Power Cooperative, Inc.’s internal control over financial reporting and compliance.

March 31, 2015


2014 2013AssetsElectric plant – at original cost:

In-service 3,836,337$ 3,765,062$ Construction-in-progress 30,790 39,602

3,867,127 3,804,664

Less accumulated depreciation 1,224,225 1,133,823 Electric plant – net 2,642,902 2,670,841

Long-term accounts receivable – 270 Debt service reserve 1,063 13,805 Investment securities:

Available for sale 33,662 29,570 Held to maturity 8,579 8,670

Current assets:Cash and cash equivalents 183,070 201,008 Deposit with RUS – restricted investment 154,313 63,256 Accounts receivable 85,812 91,314 Fuel 65,688 76,891 Materials and supplies 54,834 47,116 Regulatory assets 269 70 Emission allowances 762 956 Other current assets 6,097 5,500

Total current assets 550,845 486,111

Regulatory assets 153,587 150,273 Deferred charges 3,849 3,115 Other noncurrent assets 9,069 7,400 Total assets 3,403,556$ 3,370,055$

Members’ equities and liabilitiesMembers’ equities:

Memberships 2$ 2$ Patronage and donated capital 485,899 421,054 Accumulated other comprehensive margin (loss) (3,348) 7,686

Total members’ equities 482,553 428,742

Long-term debt 2,632,276 2,680,289

Current liabilities:Current portion of long-term debt 90,635 97,556 Accounts payable 63,808 58,235 Accrued expenses 13,950 10,443 Regulatory liabilities 14,319 4,083

Total current liabilities 182,712 170,317

Accrued postretirement benefit cost 68,918 55,410 Asset retirement obligations and other liabilities 37,097 35,297 Total members’ equities and liabilities 3,403,556$ 3,370,055$

See notes to financial statements.

December 31

East Kentucky Power Cooperative, Inc.

Balance Sheets(Dollars in Thousands)


2014 2013

Operating revenue $ 952,771 $ 903,243

Operating expenses:Production:

Fuel 297,399 292,918 Other 147,125 140,940

Purchased power 150,337 110,331 Transmission and distribution 43,130 43,790 Regional market operations 4,427 2,278 Depreciation 96,689 96,116 General and administrative 43,720 41,673

Total operating expenses 782,827 728,046

Operating margin before fixed charges 169,944 175,197

Fixed charges and other:Interest expense on long-term debt 116,148 112,306Amortization of debt expense 480 470Accretion and other 348 178

Total fixed charges and other expenses 116,976 112,954

Operating margin 52,968 62,243

Nonoperating margin:Interest income 9,853 5,268Patronage capital allocations from other cooperatives 372 598Regulatory settlements (12) (105)Other 1,664 899

Total nonoperating margin 11,877 6,660

Net margin 64,845 68,903

Other comprehensive loss:Unrealized loss on available for sale securities (82) (102)Postretirement benefit obligation gain (loss) (10,952) 22

(11,034) (80)Comprehensive margin 53,811$ 68,823$


Year Ended December 31


Statements of Revenue and Expenses and Comprehensive Margin (Dollars in Thousands)

4


AccumulatedOther Total

Patronage Donated Comprehensive Members’Memberships Capital Capital Margin (Loss) Equities

Balance – December 31, 2012 2$ 349,116$ 3,035$ 7,766$ 359,919$ Net margin – 68,903 – – 68,903 Unrealized loss on available for sale securities – – – (102) (102) Postretirement benefit obligation gain – – – 22 22

Balance – December 31, 2013 2 418,019 3,035 7,686 428,742 Net margin – 64,845 – – 64,845 Unrealized loss on available for sale securities – – – (82) (82) Postretirement benefit obligation loss – – – (10,952) (10,952)

Balance – December 31, 2014 2$ 482,864$ 3,035$ (3,348)$ 482,553$



Statements of Changes in Members’ Equities(Dollars in Thousands)


2014 2013Operating activitiesNet margin 64,845$ 68,903$Adjustments to reconcile net margin to net cash provided by

operating activities:Depreciation 96,689 96,116Amortization of loan costs 1,513 1,975Changes in operating assets and liabilities:

Accounts receivable 5,502 789Fuel 11,203 (6,109)Materials and supplies (7,718) (4,136)Regulatory assets/liabilities 10,196 (171)Emission allowances 194 310Accounts payable (2,338) (18,168)Accrued expenses 3,507 (6,007)Accrued postretirement benefit cost 2,556 1,899Other (2,844) (4,571)

Net cash provided by operating activities 183,305 130,830

Investing activitiesAdditions to electric plant (64,364) (59,596)Maturities of debt service reserve 40,379 13,766Purchases of debt service reserve securities (27,637) (13,787)Maturities of securities available for sale 52,934 52,309Purchases of securities available for sale (57,108) (52,984)Maturities of securities held to maturity 91 314Additional deposits with RUS restricted investment (277,226) (238,297)Maturities of RUS restricted investment 186,169 183,465Payments received on long-term accounts receivable 453 456Net cash used in investing activities (146,309) (114,354)

Financing activitiesProceeds from long-term debt 267,622 121,708Principal payments on long-term debt (322,556) (94,385)Net cash provided by (used in) financing activities (54,934) 27,323

Net change in cash and cash equivalents (17,938) 43,799Cash and cash equivalents – beginning of year 201,008 157,209Cash and cash equivalents – end of year 183,070$ 201,008$

Supplemental disclosure of cash flowCash paid for interest 112,820$ 112,714$Noncash investing transactions:

Additions to electric plant included in accounts payable 13,945$ 6,034$Unrealized loss on securities available for sale (82)$ (102)$


Year Ended December 31


Statements of Cash Flows(Dollars in Thousands)



Notes to Financial Statements

Years Ended December 31, 2014 and 2013

1. Summary of Significant Accounting Policies

Nature of Operations

East Kentucky Power Cooperative (the Cooperative) is a not-for-profit electric generation and transmission cooperative incorporated in 1941 that provides wholesale electric service to 16 distribution members with territories that include parts of 87 counties in Kentucky. The majority of customers served by members are residential. Each of the members has entered into a wholesale power agreement with the Cooperative, which remains in effect until 2051. The rates charged to members are regulated by the Kentucky Public Service Commission (PSC or Commission).

The Cooperative owns and operates three coal-fired generation plants, nine combustion turbines and six landfill gas plants. In addition, the Cooperative has rights to 170 megawatts of hydroelectric power from the Southeastern Power Administration.

Basis of Accounting

The financial statements are prepared in accordance with policies prescribed or permitted by the Commission and the United States Department of Agriculture, Rural Utilities Service (RUS), which conform with accounting principles generally accepted in the United States of America (GAAP) in all material respects. As a rate-regulated entity, the Cooperative’s financial statements reflect actions of regulators that result in the recording of revenues and expenses in different time periods than enterprises that are not rate regulated in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 980-10, Regulated Operations.

Electric Plant and Maintenance

Electric plant is stated at original cost, which is the cost when first dedicated to public service, including applicable labor and overhead costs.

The cost of maintenance and repairs, including renewals of minor items of property, is charged to operating expense. The cost of replacement of depreciable property units, as distinguished from minor items, is charged to electric plant. The cost of units replaced or retired, including cost of removal, net of any salvage value, is charged to accumulated depreciation.



Notes to Financial Statements (continued)

1. Summary of Significant Accounting Policies (continued)

Inventories

Inventories of fuel and materials and supplies are valued at the lower of average cost or market.

Emission Allowances

Title IV of the Clean Air Act Amendments of 1990 provides for the issuance of allowances as a means to limit the emissions of certain airborne pollutants. Allowances are stated at cost.

Issuances of allowances are recognized using a monthly weighted-average method of cost determination. Gains and losses are recorded upon the disposition of allowances.

Depreciation

Depreciation for the generating plants and transmission facilities is provided on the basis of estimated useful lives at straight-line composite rates. Rates applied to electric plant in service for both 2014 and 2013 are:

Transmission and distribution plant 0.71%–3.42% General plant 2.00%–20.00%

The Production plant assets are depreciated on a straight line basis from the date of acquisition to the end of life of the respective plant, which ranges from 2019 to 2051.

Investment Securities

Investment securities are classified as held to maturity and carried at amortized cost when management has the positive intent and ability to hold them to maturity. Investment securities are classified as available for sale when they might be sold before maturity. Investment securities available for sale are carried at fair value, with unrealized holding gains and losses reported in other comprehensive margin (loss).

Interest income includes amortization of purchase premium or discount. Gains and losses on sales are based on the amortized cost of the security sold. Investment securities are written down to fair value when a decline in fair value is other than temporary.





Restricted Investment

The Cooperative has established a cushion of credit program administered by the RUS. Under the cushion of credit program, RUS borrowers may make voluntary irrevocable deposits into a special account. The account balance accrues interest at a rate of five percent per year. The amounts in the cushion of credit account (deposits and earned interest) can only be used to make scheduled payments on loans made or guaranteed by the RUS. At December 31, 2014 and 2013, the balances in the cushion of credit program were $154.3 million and $63.3 million, respectively.

Fair Value of Financial Instruments

The carrying amount of cash, receivables and certain other current liabilities approximates fair value due to the short maturity of the instruments.

The Cooperative uses fair value to measure certain financial instruments. The fair value of a financial instrument is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (the exit price). Observable inputs or unobservable inputs, defined by ASC Topic 820-10, Fair Value Measurements and Disclosures, may be used in the calculation of fair value. ASC Topic 820-10 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The three levels of the fair value hierarchy are described below:

• Level 1 – Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;

• Level 2 – Quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly;

• Level 3 – Prices or valuations that require inputs that are both significant to the fair value measure and unobservable.

A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.





The inputs used to measure cash equivalents are Level 1 measurements, as the money market funds are exchange traded funds in an active market. The inputs used to measure the available for sale, debt service reserve and restricted investments are Level 1 measurements, as the securities are based on quoted market prices for identical investments or securities. The inputs used to measure financial transmission rights (FTR) derivatives are Level 2 measurements, as the FTR derivatives are valued based upon recent auction data from the regional transmission organization. Estimated fair values of the Cooperative’s financial instruments and methods of valuation as of December 31, 2014 and 2013, were as follows (dollars in thousands):

Fair Value at Reporting Date Using

Fair Value December 31,

2014

Quoted Prices in Active

Markets for Identical

Assets (Level 1)

SignificantOther

Observable Inputs

(Level 2)

SignificantUnobservable

Inputs(Level 3)

Cash equivalents $ 160,000 $ 160,000 $ – $ –Available for sale securities 33,662 33,662 – –Debt service reserve 1,063 1,063 – –Deposit with RUS –

restricted investment 154,313 154,313 – –FTR derivatives 1,934 – 1,934 –

Fair Value at Reporting Date Using

Fair Value December 31,

2013

Quoted Prices in Active

Markets for Identical

Assets (Level 1)

SignificantOther

Observable Inputs

(Level 2)

SignificantUnobservable

Inputs(Level 3)

Cash equivalents $ 200,000 $ 200,000 $ – $ – Available for sale securities 29,570 29,570 – – Debt service reserve 13,805 13,805 – – Deposit with RUS –

restricted investment 63,256 63,256 – – FTR derivatives 536 – 536 –





The estimated fair values of the Cooperative’s financial instruments carried at cost at December 31, 2014 and 2013, were as follows (in thousands):

2014 2013 CarryingAmount

FairValue

CarryingAmount

FairValue

Held to maturity investments $ 8,579 $ 10,571 $ 8,670 $ 8,507

Long-term debt 2,722,911 3,201,962 2,777,845 2,961,055

The inputs used to measure held to maturity investment securities are considered Level 2 and are based on third-party yield rates of similarly maturing instruments determined by recent market activity. The fair value of long-term debt, including current maturities and prepayment costs, is calculated using published interest rates for debt with similar terms and remaining maturities and is a Level 2 fair value measurement.

Regulatory Assets and Liabilities

ASC Topic 980-10 applies to regulated entities for which rates are designed to recover the costs of providing service. In accordance with this topic, certain items that would normally be reflected in the statements of revenue and expenses are deferred on the balance sheets. Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the rate-making process. Regulatory assets are charged to earnings as collection of the cost in rates is recognized or when future recovery is no longer probable. Conversely, regulatory liabilities represent future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process.

Rate Matters

Operating revenues from sales to members consist primarily of electricity sales pursuant to long-term wholesale power contracts which are maintained with each of our members. These wholesale power contracts obligate each member to pay us for demand and energy furnished in accordance with rates established by the PSC. Electricity revenues are recognized when energy is provided. Energy provided is determined based on month-end meter readings.





The base rates charged by the Cooperative are regulated by the PSC. Any change in base rates requires that EKPC file an application with the PSC and interested parties may seek intervention in the proceeding if they satisfy certain regulatory requirements. After reviewing all the documentation in the case, the Commission has ten months to complete its processing of the application and issue an order. EKPC’s last base rate case was authorized by the PSC on January 14, 2011.

The PSC has adopted a uniform fuel adjustment clause for all electric utilities within its jurisdiction. Under this clause, fuel cost above or below a stated amount per kWh is charged or credited to the member cooperatives for all energy sales during the month following actual fuel costs being incurred. The regulatory asset or liability represents the amount has been under- or over-recovered due to timing or adjustments to the mechanism.

The PSC has an environmental cost recovery mechanism that allows utilities to recover certain costs incurred in complying with the Federal Clean Air Act as amended and those federal, state, and local environmental requirements which apply to coal combustion wastes and byproducts from facilities utilized for the production of energy from coal. This environmental surcharge is billed on a percentage of revenue basis, one month following the actual costs incurred. The regulatory asset or liability represents the amount that has been under- or over-recovered due to timing or adjustments to the mechanism.

Concentration of Credit Risk

Credit risk represents the risk of loss that would occur if suppliers or customers did not meet their contractual obligations to EKPC. Concentration of credit risk occurs when significant suppliers or customers possess similar characteristics that would cause their ability to meet contractual obligations to be affected by the same events.

The Cooperative’s sales are primarily to its member cooperatives and totaled approximately $907.2 million and $882.1 million for 2014 and 2013, respectively. Accounts receivable at December 31, 2014 and 2013, were primarily from billings to member cooperatives.





At December 31, 2014 and 2013, individual account receivable balances that exceeded 10% of total accounts receivable are as follows (dollars in thousands):

2014 2013 Owen Electric Cooperative $ 12,323 $ 12,838 South Kentucky RECC 9,330 10,006Blue Grass Energy Cooperative 9,036 9,725

Cash and Cash Equivalents

The Cooperative considers temporary investments having an original maturity of three months or less when purchased to be cash equivalents. Cash equivalents at December 31, 2014 and 2013, consisted primarily of money market mutual funds and investments in commercial paper.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Asset Impairment

Long-lived assets held and used by the Cooperative are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. Specifically, the evaluation for impairment involves comparison of an asset’s carrying value to the estimated undiscounted cash flows the asset is expected to generate over its remaining life. If this evaluation were to conclude that the carrying value of the asset is impaired, an impairment charge would be recorded as a charge to operations based on the difference between the asset’s carrying amount and its fair value. No impairment was recognized for long-term assets during the years ended December 31, 2014 or 2013.





Members’ Equities

Memberships represent contributions to the Cooperative made by members. Should the Cooperative cease business, these amounts, if available, will be returned to the members.

Patronage capital represents net margin allocated to the Cooperative’s members on a contribution-to-gross margin basis pursuant to the provisions of its bylaws. The Cooperative’s bylaws prohibit the retirement of capital contributed by or allocated to members unless, after any proposed retirement, the total capital of the Cooperative equals or exceeds 20% of total assets. In addition, provisions of certain financing documents prohibit the retirement of capital until stipulated requirements as to aggregate margins and equities are met. Accordingly, at December 31, 2014 and 2013, no patronage capital was available for refund or retirement.

Comprehensive Margin

Comprehensive margin includes both net margin and other comprehensive margin (loss). Other comprehensive deficit represents the change in unrealized gains and losses on available for sale securities as well as the change in the funded status of the accumulated postretirement benefit obligation. The Cooperative presents each item of other comprehensive deficit on a net basis, in the Statements of Revenue and Expenses and Comprehensive Margin. Reclassification adjustments are disclosed in Note 10 of the Notes to Financial Statements. For any item required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period, the affected line item(s) on the Statements of Revenue and Expenses and Comprehensive Margin are provided.

Income Taxes

The Cooperative is exempt under Section 501(c)(12) of the Internal Revenue Code from federal income tax for any year in which at least 85% of its gross income is derived from members but is responsible for income taxes on certain unrelated business income. ASC Topic 740-10, IncomeTaxes, clarifies the accounting for uncertainty in income taxes recognized in the financial statements. This interpretation requires financial statement recognition of the impact of a tax position if a position is more likely than not of being sustained on audit, based on the technical merits of the position. Additionally, ASC Topic 740-10 provides guidance on measurement, recognition, classification, accounting in interim periods, and disclosure requirements for uncertain tax positions. The Cooperative has determined that more than 85% of its gross income is derived from members and it meets the exemption status under the Section 501(c)(12).





Deferred Finance Charges

The Cooperative amortizes all deferred financing charges using the effective interest method except for those charges associated with the private placement. The private placement amortizes on a straight-line basis, which approximates the effective interest method.

Derivatives

The Cooperative’s activities expose it to a variety of market risks including interest rates and commodity prices. Management has established risk management policies and strategies to reduce the potentially adverse effects that the volatility of the markets may have on its operating results. These policies and strategies include the use of derivative instruments and hedging activities. These derivative instruments generally qualify for hedge accounting or the normal purchase and normal sales exclusion under ASC Topic 815-10, Derivatives and Hedging.The Company recognizes all of its derivative instruments as either assets or liabilities in the balance sheet at fair value. If hedge treatment is obtained, unrealized gains or losses resulting from these instruments are deferred as a component of accumulated other comprehensive margin (loss) until the corresponding item being hedged is settled, at which time the gain or loss is recognized in net margin. Gains or losses for items not qualifying for hedge treatment are recognized immediately in margin. At December 31, 2014, the Cooperative had Financial Transmission Rights (FTRs) derivative assets of $1.9 million and $0.6 million in related liabilities. At December 31, 2013, the Cooperative had FTRs derivative assets of $0.5 million and $0.7 million in related liabilities. FTRs are included in other current assets and current accrued liabilities on the balance sheet.

Asset Retirement Obligations

ASC Topic 410-20, Asset Retirement Obligations, requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value when incurred and capitalized as part of the related long-lived asset. ASC Topic 410-20 clarifies the term conditional asset retirement obligation where an obligation exists even though the method or timing of settlement may be conditional. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. When the asset is retired, the entity settles the obligation for its recorded amount or incurs a gain or loss. The Cooperative’s asset retirement obligations (ARO) represent the requirements related to asbestos abatement and





reclamation and capping of ash disposal sites at its coal-fired plants. During 2014, the liabilities incurred relate to an additional ash disposal site ARO at Spurlock Station. Cash flow revisions are related to changes in the estimated cost to settle the Dale Station ash disposal site ARO.

The Cooperative continues to evaluate the useful lives of its plants and costs of remediation required by law. The following table represents the details of asset retirement obligation activity as reported on the balance sheets (in thousands):

2014 2013 Balance – beginning of year $ 32,238 $ 4,875

Liabilities incurred 1,313 27,185Cash flow revisions (1,365) –Accretion 1,077 178

Balance – end of year $ 33,263 $ 32,238

As discussed in Note 8, the PSC issued an order on March 6, 2015 granting regulatory asset treatment of ARO accretion and depreciation retroactive to January 1, 2014 for all AROs except for ash hauling associated with the Dale ash disposal site ARO. Regulatory assets for the applicable AROs were established at December 31, 2014, and accordingly, only $0.3 million accretion expense was recognized in 2014.

New Accounting Standards

In February 2013, the FASB issued Accounting Standards Update (ASU) 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU 2013-02). ASU 2013-02 requires an entity to provide information in one location about amounts reclassified out of AOCI by component and their corresponding effect on net income if the amount reclassified is required under U.S. GAAP to be reconciled to net income in its entirety in the same reporting period. For other amounts not required to be reclassified to net income in their entirety, such as pension-related amounts, an entity is required to cross-reference to related footnote disclosures. The amendments in ASU 2013-02 were effective prospectively for non-public companies for the fiscal years beginning after December 15, 2013. The disclosures required by ASU 2013-02 have been included in Note 10 of the Notes to Financial Statements.





Regional Transmission Organization

Effective June 1, 2013, the Cooperative became a transmission-owning member of PJM Interconnection, LLC (PJM) and functional control of certain transmission facilities was transferred to PJM at that time. Open access to the EKPC transmission system is managed by PJM pursuant to the FERC approved PJM Open Access Transmission Tariff and the Cooperative is an active participant in PJM’s Regional Transmission Planning process, which develops a single approved transmission plan for the entire PJM footprint. Energy related purchases and sales transactions within PJM are recorded on an hourly basis with all transactions within each market netted to a single purchase or sale for each hour.

Reclassifications

A reclassification was made in the statement of cash flows for the year ended December 31, 2013, to correct for an error related to the identification of cash used for additions to plant. The change in classification increased net cash provided by operating activities and increased net cash used in investing activities by $13.3 million, respectively. The reclassification did not impact the net change in cash and cash equivalents for the year.

New Accounting Guidance Pending Adoption

On May 28, 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers (Topic 606),” or ASU 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.

ASU 2014-09 will supersede the revenue recognition requirements in the Revenue Recognition Topic 605 of the ASC and most industry-specific guidance, and creates the Revenue from Contracts with Customers Topic 606 of the ASC. ASU 2014-09 will be effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is not permitted. The Company is currently assessing the impact of adopting this guidance, as well as the transition method it will use.




2. Electric Plant in Service

Electric plant in-service at December 31, 2014 and 2013, consisted of the following (in thousands):

2014 2013 Production plant $ 2,919,341 $ 2,892,532 Transmission plant 733,646 729,968General plant 108,233 101,737Completed construction, not classified, and other 75,117 40,825Electric plant in service $ 3,836,337 $ 3,765,062

Electric plant in service at December 31, 2014 includes Dale Station generating assets, which were originally placed in service in 1954. Dale Station consists of four units and is accounted for as one asset with an original cost of approximately $94.6 million. Dale Station is not currently MATS compliant and EKPC has made no plans to invest in additional environmental compliance equipment at Dale Station. Therefore it is expected that Dale Station could retire before the end of its depreciable life of June 30, 2019. However, at the request of PJM, EKPC applied for a one year MATS extension to address reliability concerns. On January 6, 2015, the Kentucky Division of Air Quality granted a compliance extension for Dale Units 3 and 4 until April 15, 2016. The Board of Directors has authorized management to seek regulatory asset treatment for the remaining net book value of Dale Station when it ceases all coal generating operations, which is currently expected to be on April 15, 2016. The estimated net book value of Dale Station at April 15, 2016 is $2.9 million. Management believes it is probable that the PSC will allow the Cooperative to recover the full amount through rates.

3. Long-Term Accounts Receivable

Long-term accounts receivable represents interest-bearing notes from joint ventures owned by the Cooperative and four of the Cooperative’s member systems for the buyout of a propane company. The joint ventures of the member systems make principal and interest (prime rate minus one-half of one percent, adjusted annually) payments. The notes are payable in full in 2015. Accordingly, the outstanding balance at December 31, 2013, of $0.3 million was reclassified to other current assets at December 31, 2014.




4. Investment Securities

Amortized cost and estimated fair value of investment securities available for sale at December 31, 2014 and 2013, were as follows (dollars in thousands):

Amortized Cost

GrossUnrealized

Gains

GrossUnrealized

LossesFair

Value2014U.S. Treasury Bill $ 6,864 $ 86 $ – $ 6,950 Zero coupon bond 26,712 – – 26,712 $ 33,576 $ 86 $ – $ 33,662

Amortized Cost

GrossUnrealized

Gains

GrossUnrealized

LossesFair

Value2013U.S. Treasury Bill $ 26,209 $ 1 $ – $ 26,210 Zero coupon bond 3,193 167 – 3,360

$ 29,402 $ 168 $ – $ 29,570

Proceeds from maturities of securities were $52.9 million and $52.3 million in 2014 and 2013, respectively.




4. Investment Securities (continued)

Amortized cost and estimated fair value of investment securities held to maturity at December 31, 2014 and 2013, are as follows (dollars in thousands):

Amortized Cost

GrossUnrealized

Gains

GrossUnrealized

Losses Fair

Value2014 National Rural Utilities Cooperative

Finance Corporation: 3%–5% capital term certificates $ 7,656 $ 1,941 $ – $ 9,597 6.5875% subordinated

term certificate 300 107 – 407 0% subordinated term certificate 623 – (56) 567

$ 8,579 $ 2,048 $ (56) $ 10,571

Amortized Cost

GrossUnrealized

Gains

GrossUnrealized

Losses Fair

Value2013 National Rural Utilities Cooperative

Finance Corporation: 3%–5% capital term certificates $ 7,656 $ 24 $ (196) $ 7,484 6.5875% subordinated

term certificate 325 100 – 425 0% subordinated term certificate 689 – (91) 598

$ 8,670 $ 124 $ (287) $ 8,507




4. Investment Securities (continued)

All investment securities held to maturity with unrealized losses at December 31, 2014 and 2013, have maturities of 12 months or more. The amortized cost and fair value of securities at December 31, 2014, by contractual maturity, are shown below (dollars in thousands). Expected maturities may differ from contractual maturities because certain borrowers may have the right to call or prepay obligations with or without call or prepayment penalties.

Amortized Cost

FairValue

Available for sale:

Due in one year or less $ 26,712 $ 26,712 Due after one year through five years 6,864 6,950

$ 33,576 $ 33,662 Held to maturity:

Due after one year through five years $ 50 $ 49 Due after five years through ten years 1,531 1,621 Due after ten years 6,998 8,901

$ 8,579 $ 10,571

5. Long-Term Debt

The Cooperative executed an Indenture of Mortgage, Security Agreement and Financing Statement, dated as of October 11, 2012 (Indenture) between the Cooperative, as Grantor, to U.S. Bank National Association, as Trustee. The Indenture provides secured note holders with a pro-rated interest in substantially all owned assets.




5. Long-Term Debt (continued)

Long-term debt outstanding at December 31, 2014 and 2013, consisted of the following (in thousands):

2014 2013 First mortgage notes:

2.30%–10.66%, payable quarterly to Federal Financing Bank (FFB) in varying amounts through 2044, weighted average 4.30% $ 2,407,968 $ 2,445,661

5.13% payable quarterly to RUS in varyingamounts through 2024 6,753 7,317

Variable rate, 3.30% at December 31, 2014 and 2013, payable quarterly to CFC in varying amounts through 2024 6,384 6,936

Variable rate, 3.30% at December 31, 2014 and 2013, payable quarterly to CFC in varying amounts through 2019 2,095 2,520

First Mortgage Bonds, Series 2014A, fixed rate of 4.61%, payable semi-annual, matures February 6, 2044 200,000 –

Tax-exempt bonds: Pollution control revenue bonds, Series 1984B, variable

rate bonds, due October 15, 2014, 0.30% at December 31,2013 – 12,700

Solid waste disposal revenue bonds, Series 1993B, variable rate bonds, due August 15, 2023 0.50% and 0.65% at December 31, 2014 and 2013, respectively 5,500 6,000

Clean Renewable Energy Bonds, Fixed rate of 0.40% payable quarterly to CFC to December 1, 2023 4,845 5,383

Promissory notes: Variable rate note payable to CFC, 1.17% at

December 31, 2014 75,000 275,0004.68% fixed rate notes payable to National Cooperative

Services Corporation 14,366 16,3282,722,911 2,777,845

Less current portion of long-term debt 90,635 97,556$ 2,632,276 $ 2,680,289





First Mortgage Notes and Bonds

The Cooperative received loan funds in varying amounts through its first mortgage notes payable to the Federal Financing Bank. All such loans are subject to certain conditions outlined by RUS. Listed below are descriptions of those loan applications for which additional funds were advanced to the Cooperative during the year and the status of any remaining funds approved and available for advance at December 31, 2014.

In July 2008, the Cooperative submitted to RUS a loan application in the amount of $152.7 million for various transmission projects. This loan was revised in July 2008 to $140.7 million. This loan was approved by RUS in July 2009 and matures on December 31, 2040. The Cooperative received an advance on this loan of $21.0 million on December 19, 2014. As of December 31, 2014, $39.3 million of these amounts remained available for advance.

In March 2009, EKPC submitted to RUS a loan application for $341 million for construction of the Cooper Station Retrofit Air Pollution Project. This loan was approved by RUS in August 2009 with a maturity date of December 31, 2044. The Cooperative received an advance on this loan of $21.6 million on December 19, 2014. As of December 31, 2014, $116.1 million of these amounts remained available for advance.

In accordance with the Rural Electrification Act of 1936 (RE Act), as amended, the RUS established a cushion of credit program. Under this program, RUS borrowers may make voluntary deposits into a special cushion of credit account. This cushion of credit account balance accrues interest at a rate of 5% per annum. The amounts in the cushion of credit account (deposits and earned interest) can only be used to make scheduled payments on loans made or guaranteed under the RE Act. The Cooperative’s cushion of credit account balance was $154.3 million and $63.3 million at December 31, 2014 and 2013, respectively. These balances were used to make scheduled debt payments to RUS in the subsequent year. Accordingly, these amounts were recorded as restricted current investments as of December 31, 2014 and 2013.

On December 11, 2013, the Cooperative entered into a Bond Purchase Agreement for $200 million 4.61% First Mortgage Bonds, Series 2014A due February 2044. The transaction closed and funded on February 6, 2014. The debt is secured on equal footing with the Cooperative’s other secured debt under the Indenture.





Promissory Note–Unsecured Credit Facility

On August 9, 2011, the Cooperative entered into an unsecured credit facility syndicate with the joint lead arrangers of CFC, KeyBank, and PNC Capital Markets. This loan was approved for a total of $450 million for general operating expenses and capital construction projects. On October 3, 2013, this agreement was amended and extended to $500 million to expire on October 3, 2018. As of December 31, 2014, $425 million of this amount remained to be advanced.

Tax Exempt Bonds

The Cooperative’s Series 1984B Pollution Control Bonds matured on October 15, 2014 and were paid in full. A $12.7 million CFC guarantee secured payment of the Series 1984B bonds expired on October 15, 2014 at the maturity of the debt. In addition, the Cooperative maintained a $12.7 million debt service reserve fund with a trustee throughout the term of the bonds; the requirement for the debt service reserve fund expired at October 15, 2014.

The interest rate on the Series 1993B Solid Waste Disposal Revenue Bonds is subject to change semiannually. The interest rate adjustment period on the variable rate bonds may be converted to a weekly, semiannual, annual or three-year basis, or to a fixed-rate basis, at the option of the Cooperative. A $6.0 million CFC guarantee secures payment of the Series 1993B bonds and has an expiration date of August 15, 2023. The 1993B solid waste disposal revenue bonds require that debt service reserve funds be on deposit with a trustee throughout the term of the bonds in the amount of $1.1 million. In addition, mandatory sinking fund payments are required ranging from $0.5 million in 2014 to $0.7 million in 2023. Debt service reserve and construction funds are held by a trustee and are invested primarily in U.S. Government securities and CFC promissory notes. These funds are included in debt service on the accompanying balance sheets and have a fair value of approximately $1.1 million at December 31, 2014 and 2013.





Estimated annual maturities of long term debt for the five years subsequent to December 31, 2014, are as follows (dollars in thousands):

Years ending December 31 2015 $ 90,635 2016 91,732 2017 89,853 2018 90,722 2019 92,234 Thereafter 2,267,735 $ 2,722,911

The Indenture and certain other debt agreements contain provisions which, among other restrictions, require the Cooperative to maintain certain financial ratios. The Cooperative was in compliance with these financial ratios at December 31, 2014 and 2013, respectively.

As of December 31, 2014, the Cooperative has $3.3 million outstanding in a letter of credit with the Commonwealth of Kentucky for Worker’s Compensation.

As of December 31, 2014, the Cooperative has pledged securities of $6.7 million with the United States Department of Labor for Federal Longshore Harbor Workers and the Commonwealth of Kentucky.

6. Retirement Benefits

Pension Plan

Pension benefits for employees hired prior to January 1, 2007, are provided through participation in the National Rural Electric Cooperative Association (NRECA) Retirement and Security Plan (RS Plan). The plan is a defined benefit pension plan qualified under Section 401 and tax exempt under Section 501(a) of the Internal Revenue Code. It is a multiemployer plan under the accounting standards. The plan sponsor’s Employer Identification Number is 53-0116145 and the Plan Number is 333.




6. Retirement Benefits (continued)

A unique characteristic of a multiemployer plan compared to a single employer plan is that all plan assets are available to pay benefits of any plan participant. Separate asset accounts are not maintained for participating employers. This means that assets contributed by one employer may be used to provide benefits to employees of other participating employers.

The Cooperative’s contributions to the RS Plan in 2014 and 2013, represented less than 5 percent of the total contributions made to the plan by all participating employers. The Cooperative made contributions to the plan of $8.5 million and $9.7 million in 2014 and 2013, respectively. There have been no significant changes that affect the comparability of 2014 and 2013 contributions.

For the RS Plan, a “zone status” determination is not required and therefore, not determined, under the Pension Protection Act (PPA) of 2006. In addition, the accumulated benefit obligations and plan assets are not determined or allocated separately by individual employer. In total, the RS Plan was over 80 percent funded on January 1, 2014 and over 80 percent funded on January 1, 2013, based on the PPA funding target and PPA actuarial value of assets on those dates. Because the provisions of the PPA do not apply to the RS Plan, funding improvement plans and surcharges are not applicable. Future contribution requirements are determined each year as part of the actuarial valuation of the plan and may change as a result of plan experience.

Retirement Savings Plan

The Cooperative has a Retirement Savings Plan for all employees who are eligible to participatein the Cooperative’s benefit programs. The plan allows participants to make contributions by salary reduction, pursuant to Section 401(k) of the Internal Revenue Code. For employees hired prior to January 1, 2007, the Cooperative makes matching contributions to the account of each participant up to 2.0% of the participant’s compensation. For employees hired on or after January 1, 2007, the Cooperative will automatically contribute 6.0% of base wages and match the employee contribution up to 4.0%. The Cooperative contributed approximately $2.3 million and $2.1 million to the plan for the years ended December 31, 2014 and 2013, respectively. Employees vest immediately in their contributions and the contributions of the Cooperative.





Supplemental Executive Retirement Plan

The Cooperative provides a 457(f) Supplemental Executive Retirement Plan to executives of the organization. The plan is considered a defined contribution plan whereby annual contributions are made based upon a percentage of base salary. Participants become 100% vested and the account balance paid out upon attaining age 62 or if separation occurs due to involuntary termination without cause, disability, or death. Separation for any other reason before age 62 will result in participants forfeiting their benefits.

Supplemental Death Benefit Plan

The Cooperative provides a Supplemental Death Benefit Plan to all employees eligible to participate in the pension plan. The supplemental death benefit is payable to a deceased employee’s beneficiary if the lump sum value of a 100% survivor benefit under the pension plan exceeds the pension plan benefits plus the Cooperative’s group life insurance proceeds. Management believes that any liability related to this plan will not have a material effect on the financial statements.

Postretirement Medical Benefits

The Cooperative sponsors a defined benefit plan that provides medical and life insurance coverage to retirees and their dependents. Participating retirees and dependents contribute 50% of the projected cost of coverage. For purposes of the liability estimates, the substantive plan is assumed to be the same as the written plan. The plan is not funded.





The following sets forth the accumulated postretirement benefit obligation, the change in plan assets, and the components of accrued postretirement benefit cost and net periodic benefit cost as of December 31, 2014 and 2013 (dollars in thousands):

2014 2013

Change in benefit obligation: Accumulated postretirement benefit obligation –

beginning of year $ 57,626 $ 55,008 Service cost 1,223 1,399 Interest cost 2,871 2,355 Plan participants’ contributions 1,220 964 Benefits paid (2,569) (1,934)Actuarial (gain) loss 10,835 (166)

Accumulated postretirement benefit obligation – end of year $ 71,206 $ 57,626

Change in plan assets: Fair value of plan assets – beginning of year $ – $ –

Employer contributions 1,349 970 Participant contributions 1,220 964 Benefits paid (2,569) (1,934)

Fair value of plan assets – end of year – –Funded status – end of year $ (71,206) $ (57,626)

Amounts recognized in balance sheet consists of: Current liabilities $ 2,288 $ 2,216 Noncurrent liabilities 68,918 55,410

Total amount recognized in balance sheet $ 71,206 $ 57,626

Amounts included in accumulated other comprehensive margin – unrecognized actuarial gain (loss) $ (3,434) $ 7,518

Net periodic benefit cost: Service cost $ 1,223 $ 1,399 Interest cost 2,871 2,355 Amortization of net actuarial gain (117) (145)

Net periodic benefit cost $ 3,977 $ 3,609 `Net gain (loss) recognized in other comprehensive margin $ (10,952) $ 22 Amounts expected to be realized in next fiscal year – amortization

of net gain $ – $ (117)





The discount rate used to determine the accumulated postretirement benefit obligation was 4.28% and 5.08% for 2014 and 2013, respectively. This decrease in the discount rate of eighty basis points resulted in $8.7 million of the $10.8 million actuarial loss for the year ended December 31, 2014.

The Cooperative expects to contribute approximately $2.3 million to the plan in 2015.

The following expected benefit payments from the plan, which reflect anticipated future service, are (dollars in thousands):

Years ending December 31: 2015 $ 2,288 2016 2,421 2017 2,535 2018 2,656 2019 2,786 2020–2024 15,632

Total $ 28,318

For measurement purposes, a 7.1% annual rate of increase in the per capita cost of covered health care benefits was used for the year ended December 31, 2014. The rate is assumed to decline to 4.5% after 13 years. The health care cost trend rate assumption has a significant effect on the amounts reported. For example, a 1% increase in the health care trend rate would increase the service and interest costs $1.0 million and increase the postretirement benefit obligation by $13.9 million. A 1% decrease in the health care trend rate would decrease total service and interest costs by $0.8 million and decrease the postretirement benefit obligation by $11.0 million.




7. Commitments and Contingencies

The Cooperative has entered into long-term agreements for the purchase of power, with the final agreement expiring in 2016. Payments made under the contracts for 2014 and 2013 were $19.7 million and $16.8 million, respectively, and total minimum payment obligations are as follows (dollars in thousands):

Years ending December 31: 2015 $ 40,844 2016 5,643

The Cooperative is committed to purchase coal for its generating plants under long-term contracts that extend through 2021. Coal payments under contracts for 2014 and 2013 were $141.6 million and $188.2 million, respectively. Total minimum purchase obligations for the next five years are as follows (dollars in thousands):

Years ending December 31: 2015 $ 170,115 2016 168,075 2017 59,457 2018 4,079 2019 1,484

The minimum cost of the coal purchases, based on the latest contractual prices, is subject to escalation clauses that are generally based on government-published indices and market price.

The supply agreements are not accounted for as derivatives based upon the Normal Purchases Normal Sales exception as permitted by ASC Topic 815-10, Derivatives and Hedging.

There are pending civil claims in litigation against the Cooperative. Under the Cooperative’s general liability insurance program, it is responsible for a deductible amount up to $1 million for each occurrence. Neither the probable outcome nor ultimate liability resulting from any claims and litigation can be readily determined at this time. Accruals have been made when appropriate and management believes that any liability for such matters will, in any case, not have a material effect on the financial statements.




7. Commitments and Contingencies (continued)

The Cooperative and 15 of its owner-members have been named in a complaint filed by another East Kentucky Power Cooperative owner-member (plaintiff). The plaintiff claims, among other things, that it owned a portion of Charleston Bottoms Rural Electric Cooperative Corporation, which was dissolved in 2012 with all assets conveyed to EKPC, and thereby, is entitled to its share of the fair market value of the assets at the time of dissolution. EKPC is vigorously contesting the complaint and has filed motions accordingly.

8. Regulatory Assets and Liabilities

In 2010, the Cooperative recorded a regulatory asset of $157.1 million for construction costs expended on the cancelled Smith Unit 1 plant based on the guidance for abandonment of plant costs for regulated entities and management’s assertion that full return on investment was probable. On February 28, 2011, the PSC approved the Cooperative’s request to surrender the Certificate of Public Convenience and Necessity (CPCN) for Smith Unit 1 and in a separate order, authorized the establishment of a regulatory asset for the construction costs incurred and the Cooperative’s estimate of the costs to unwind vendor contracts. During 2011, the Cooperative negotiated final settlement of the Smith Unit 1 contracts, resulting in a reduction of the regulatory asset balance to $150.8 million at December 31, 2011. Additional minimal costs have been incurred each year to maintain the assets. The balance of the regulatory asset was reduced by a $1 million non-refundable exclusivity payment from a prospective buyer in 2013. The balance was reduced by an additional $0.9 million in 2014 for parts used by another EKPC generating unit for maintenance to bring the regulatory asset balance to $149.4 million at December 31, 2014. While the Cooperative has not yet requested rate recovery, management believes that it is probable that the PSC will allow the Cooperative to recover through rates the full amount of the regulatory asset, along with a return on the investment, net of cash inflows from cost mitigation efforts.

On March 6, 2015, the PSC approved EKPC’s request to recognize deprecation and accretion expenses related to its asbestos abatement and ash disposal AROs as regulatory assets for 2014 and all subsequent years with the exception of a portion of one ARO associated with ash transfer costs at Dale Station. EKPC has requested a rehearing to address the component of the ARO excluded from regulatory asset treatment and to gain clarity on other requirements outlined in the order. Also, in a separate proceeding, the Cooperative requested and the PSC approved recovery of the costs that will settle the Dale Station ash disposal ARO through the environmental surcharge mechanism. The associated regulatory asset will be expensed as recovery occurs. While the Cooperative has not yet requested recovery of the other ARO related regulatory assets, management believes it is probable that the PSC will allow the Cooperative to recover the full amount through rates or other mechanisms.




8. Regulatory Assets and Liabilities (continued)

In 2008, the Cooperative recorded a regulatory asset of $12.3 million related to unrecorded forced outage replacement power costs incurred during 2008. The PSC approved a three-year amortization period beginning in April 2009. In conjunction with the rate case approved by the PSC on January 14, 2011, the Cooperative was permitted to extend the amortization of forced outage costs an additional three years until January 14, 2014. Accordingly, this regulatory asset, along with deferred management audit costs, was classified as a current regulatory asset at December 31, 2013.

On January 30, 2015, the PSC issued an order disallowing purchased power costs included in the fuel adjustment clause recovery mechanism (FAC) of $8.5 million that were in excess of EKPC’s own highest-cost generating unit available to be dispatched to serve native load from November 1, 2013 through April 30, 2014. The PSC directed EKPC to refund this amount through the FAC over four consecutive months in 2015. Accordingly, this amount, along with an additional $1.3 million estimated by EKPC for the months of May 2014 through December 2014 was included in the FAC regulatory liability at year-end. EKPC requested a rehearing on this matter and the PSC approved the request for rehearing on March 6, 2015.

Regulatory assets (liabilities) were comprised of the following as of December 31, 2014 and 2013 (dollars in thousands):

2014 2013 Plant abandonment – Smith Unit 1 $ 149,384 $ 150,273 ARO-related depreciation and accretion expenses 4,203 –Environmental cost recovery 269 –Deferred outage costs – 60Deferred management audit costs – 10

$ 153,856 $ 150,343

Fuel adjustment clause $ (14,319) $ (1,089)Environmental cost recovery – (2,994)

$ (14,319) $ (4,083)




9. Environmental Matters

In June 2014, EPA proposed new rules under Section 111(d) of the Clean Air Act to regulate greenhouse gas emissions from existing power utilities. EKPC provided detailed comments on this rule. EPA anticipates finalizing all rules regarding carbon dioxide emissions from the power sector in 2015. Although EPA has proposed that interim carbon dioxide emission goals must be met between 2020 and 2029 and that final carbon dioxide emission goals must be achieved by 2030, compliance requirements and deadlines will not be certain until the rule is finalized.

Existing coal and oil fired electric utility steam generating units must comply with Mercury and Air Toxics Standards (MATS) rules to reduce emissions of air toxins by April 15, 2015. A one year extension until April 15, 2016 may be granted under certain circumstances. EKPC’s Cooper and Dale Stations have received a one-year compliance extension, until April 15, 2016. The extension for Dale was granted because the units are expected to be needed to be available to operate during the upcoming year to ensure reliability of the power grid, as requested by PJM. Cooper obtained the extension to provide EKPC with additional time to complete installation of the necessary environmental controls. Unit 4 at Spurlock Station is already in compliance with MATS per an Agreed Consent Order with the Commonwealth of Kentucky. Units 1, 2 and 3 at Spurlock Station will begin MATS compliance on April 15, 2015.

On December 30, 2012, the DC Court of Appeals stayed the Cross-State Air Pollution Rule (CSAPR) to limit S02 and NOx emissions pending judicial review. In April of 2014, the Supreme Court reversed the DC Court of Appeals, reinstating CSAPR. This decision prompted the DC Court of Appeals to lift the stay on October 23, 2014. Phase 1 of CSAPR began on January 1, 2015 and Phase 2 will begin on January 1, 2017.

In August 2014, EPA published its final rule under Section 316(b) of the Clean Water Act, regulating the location, design, construction, and capacity of cooling water intake systems. The rule became effective on October 14, 2014. The rule requires facilities that withdraw 2 million gallons per day and use 25% of the withdrawn water exclusively for cooling purposes to ensure that the cooling water intake structures implement the best technology available (BTA) to minimize impingement and entrainment of fish and other aquatic organisms. EPA does not dictate what technology must be used, but provides seven BTA options. Kentucky is responsible for establishing a compliance schedule for the 316(b) rule in connection with the renewal of the Cooperative’s existing permits.




9. Environmental Matters (continued)

In December 2014, EPA released its rule regulating management of coal combustion residuals (CCR) under the Resource Conservation and Recovery Act. To date, the final rule has not been published in the Federal Register. The rule is expected to be effective 180 days after its publication in the Federal Register. The final rule applies to owners and operators of landfills and surface impoundments and establishes minimum national criteria for the safe disposal of solid waste CCR. The criteria address a wide spectrum of activities related to CCR solid waste disposal. Areas addressed include location restrictions, structural integrity requirements, liner design criteria, operations, groundwater monitoring, closure and postclosure requirements. Also, the closure and postclosure requirements may result in additional asset retirement obligations in the period it becomes a legal obligation.

The Cooperative is evaluating the impact of these rules on its current fleet of coal-fired units.

10. Changes in Accumulated Other Comprehensive Margin (Loss) by Component

The following table represents the details of accumulated other comprehensive margin activity by component (in thousands):

Postretirement Benefit

Obligation

Unrealized Gain (Loss) on

Investments Available for

Sale

Accumulated Other

Comprehensive Margin (Loss)

Balance – December 31, 2013 $ 7,518 $ 168 $ 7,686

Other comprehensive loss before reclassifications (10,835) (82) (10,917)Amounts reclassified from accumulated

other comprehensive margin (117) – (117)Net current period other comprehensive loss (10,952) (82) (11,034)Balance – December 31, 2014 $ (3,434) $ 86 $ (3,348)

The postretirement benefit obligation reclassification noted above represents the amortization of actuarial gain that is included in the computation of net periodic postretirement benefit cost. See Note 6 – Retirement Benefits for additional details.




11. Related-Party Transactions

The Cooperative is a member of the National Rural Utilities Cooperative Finance Corporation (CFC), which provides a portion of the Cooperative’s financing and is also a joint lead arranger and a 16% participant in the Cooperative’s $500 million unsecured credit facility. Investments held to maturity included CFC capital term certificates of $8.6 million and $8.7 million at December 31, 2014 and 2013, respectively. CFC Patronage capital assigned to EKPC was $1.3 million and $1.2 million at December 31, 2014 and 2013, respectively.

The Cooperative is also a member of CoBank, which is a 13.4% participant in the Cooperative’s $500 million unsecured credit facility. The balance of CoBank patronage capital assigned to EKPC at December 31, 2014 and 2013, was $0.3 million and $0.2 million, respectively.

EKPC is a member of ACES LLC (ACES), which provides various energy marketing, settlement and risk management related services to its members and clients. EKPC’s Chairman of the Board is the Treasurer on ACES Board of Managers. EKPC’s CEO is also an ACES Board Member. EKPC accounts for its investment in ACES on the cost basis of accounting. At December 31, 2014 and 2013, the balance of EKPC’s investment in ACES was approximately $0.6 million. Payments to ACES were $2.2 million in 2014 and $2.1 million in 2013.

12. Subsequent Events

On March 6, 2015, the PSC granted EKPC a Certificate of Public Convenience and Necessity (CPCN) to construct the Smith Landfill to receive coal ash removed from the Dale ash ponds. The total project is for $27 million and also includes reclamation of the Dale ash pond site and transfer of the ash from Dale to the Smith location. The PSC also approved EKPC’s request to recover the costs of the project, with the exception of ash transfer costs, through the environmental surcharge over a 10 year period. The order requires ash transfer costs to be recovered through the environmental surcharge as incurred.

Management has evaluated subsequent events through March 31, 2015, which is the date these financial statements were available to be issued.


4775 Lexington Road, 40391P.O. Box 707,Winchester, KY 40392-0707Telephone: 859-744-4812Fax: 859-744-6008www.ekpc.coop

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