Cooperative Value - Tri-State Generation and Transmission

Transcription

2012
ANNUAL
REPORT
Cooperative Value
Tri-State Generation and Transmission
Association is a wholesale electric power
supplier owned by the 44 member
systems we serve in Colorado, Nebraska,
New Mexico and Wyoming.
WHILE WE GENERATE AND TRANSMIT ELECTRICITY AROUNDTHE-CLOCK TO OUR MEMBER CO-OPS ACROSS A 200,000
SQUARE-MILE SERVICE TERRITORY, WHAT WE REALLY STRIVE
TO DELIVER IS VALUE.
MEMBER
DISTRIBUTION
SYSTEMS
Bh Big Horn Rural Electric Company
Basin, Wyoming
Cb Carbon Power & Light
Saratoga, Wyoming
Cn Central New Mexico Electric
Cooperative
2,798
1,870
MEMBER PEAK
DEMAND
18.7
TOTAL
ENERGY SALES
(MwH)
Bayard, Nebraska
Co Columbus Electric Cooperative
15.7
Montrose, Colorado
Em Empire Electric Association
3.0
Cortez, Colorado
Gl Garland Light & Power Company
Powell, Wyoming
Gc Gunnison County Electric
Association
ENERGY SALES TO
NON-MEMBERS
GENERATING CAPACITY,
NATURAL GAS/OIL
Grants, New Mexico
Dm Delta-Montrose Electric Association
(MwH)
969
Deming, New Mexico
Cd Continental Divide Electric
Cooperative
ENERGY SALES TO
MEMBERS
GENERATING CAPACITY,
COAL
Mountainair, New Mexico
Cr Chimney Rock Public Power District
(MwH)
Gunnison, Colorado
Hp High Plains Power
Riverton, Wyoming
1
Headquarters and Operations Center
2
Craig Station
3
Nucla Station
4
Burlington Station
5
J.M. Shafer Generating Station
6
Limon Generating Station
7
Frank R. Knutson Generating Station
8
Rifle Generating Station
Rifle, Colorado
9
Laramie River Station
1.3
807
TOTAL OPERATING
REVENUE
RENEWABLE ENERGY
RESOURCES
2012 by the Numbers
592
52.8
CONTRACTED GENERATING
CAPACITY
NET MARGINS
5,306
4.3
MILES OF
TRANSMISSION
LINE
ASSETS
EMPLOYEES
(includes subsidiaries)
610,565
MEMBER
CONSUMER-METERS
44
Craig, Colorado
Nucla, Colorado
Burlington, Colorado
Fort Lupton, Colorado
Limon, Colorado
Brighton, Colorado
Wheatland, Wyoming
10 Escalante Generating Station
Prewitt, New Mexico
6.8
1,517
Westminster, Colorado
11 San Juan Generating Station
Farmington, New Mexico
12 Pyramid Generating Station
Lordsburg, New Mexico
AVERAGE WHOLESALE
RATE TO MEMBERS
(per KwH)
13 Springerville Generating Station
Springerville, Arizona
14 David A. Hamil DC Tie
Stegall, Nebraska
MEMBER SYSTEMS
15 Cimarron Solar Facility*
Springer, New Mexico
MAJOR
TRI-STATE
RESOURCES
16 Kit Carson Windpower Project*
Burlington, Colorado
17
COLORADO HIGHLANDS WIND*
Fleming, Colorado
*Long-term purchase power arrangements.
Hw High West Energy
NbNiobrara Electric Association
SrSierra Electric Cooperative
Hl Highline Electric Association
NrNorthern Rio Arriba Electric
Cooperative
SoSocorro Electric Cooperative
Pine Bluffs, Wyoming
Holyoke, Colorado
Jm Jémez Mountains Electric Cooperative
Española, New Mexico
Taos, New Mexico
Durango, Colorado
Grant, Nebraska
Granby, Colorado
Pueblo West, Colorado
Nucla, Colorado
BH
HP
HP
NB
WL
NW
WY
PH
RS
9
CB
CR
14
WB
HW
CO
MW
17
PV
5
MP
2
WR
HI
YW
7
1
6
MV
KC
SC
SM
SI
LP
SE
SV
NR
11
KT
SP
SW
15
JM
10
MO
CD
CN
SO
SR
16
4
DM
GC
NE
MC
UN
8
OC
12
NM
CO
1
Wheatland, Wyoming
Meeker, Colorado
Lingle, Wyoming
YwY-W Electric Association
Buena Vista, Colorado
HP
Sidney, Nebraska
WyWyrulec Company
GL
13
Brighton, Colorado
WrWhite River Electric Association
Monte Vista, Colorado
EM
Springer, New Mexico
SiSan Isabel Electric Association
3
Clayton, New Mexico
SpSpringer Electric Cooperative
WlWheatland Rural Electric
Association
ScSangre de Cristo Electric
Association
WY
SmSan Miguel Power Association
Limon, Colorado
La Junta, Colorado
SwSouthwestern Electric
Cooperative
WbWheat Belt Public Power District
Mitchell, Nebraska
MvMountain View Electric Association
SvSan Luis Valley Rural Electric
Cooperative
MpMountain Parks Electric
Socorro, New Mexico
SeSoutheast Colorado Power
Association
RsRoosevelt Public Power District
Fort Morgan, Colorado
Elephant Butte, New Mexico
UnUnited Power
Fort Collins, Colorado
Mora, New Mexico
McMorgan County Rural Electric
Association
Alliance, Nebraska
PvPoudre Valley Rural Electric
Association
MoMora-San Miguel Electric Cooperative
Cloudcroft, New Mexico
PhPanhandle Rural Electric Membership
Association
MwThe Midwest Electric
Cooperative Corporation
Hay Springs, Nebraska
OcOtero County Electric Cooperative
LpLa Plata Electric Association
Chama, New Mexico
Hugo, Colorado
Kt Kit Carson Electric Cooperative
NwNorthwest Rural Public Power District
Kc K.C. Electric Association
Lusk, Wyoming
Akron, Colorado
Cooperative Value
COLLABORATION
EQUITY
RELIABILITY
AGGREGATION
STEWARDSHIP
PRODUCTIVITY
The electric cooperative business model has a long history and proven track record of success. It’s
an ongoing story of different people and organizations joining to share resources and work toward
common goals on behalf of the co-ops’ member-owners. The primary mission has always been to
produce and deliver reliable, affordable and responsible electricity, while enriching lives and energizing rural communities and economies through the cooperative value.
LETTER
FROM THE
CHAIRMAN
The Tri-State board spent a considerable amount of time this past year addressing all five of our
strategic goals.
Our first and foremost goal to the membership is to provide reliable, affordable power to our
member co-ops. The influence that policymakers have on our mission can be critical. We feel it is
important to educate them on the impact they may have on our members, even if our members
may not be their immediate constituents.
Regulation mitigation also continues to be a primary concern. A key component of this goal is to
preserve Tri-State’s ability to keep technology and resource options open for as long as possible to
meet future resource needs. This is becoming critical in dealing with the onslaught of environ
mental regulations on our current and potential future production fleet.
A lot of work was done in 2012 integrating into our operations the Colowyo coal mine and
J.M. Shafer Station asset purchases the board approved in late 2011. These facilities fit into the
board’s strategic goal of long-range resource and fuel planning. They also assist with our mission
of providing the membership with reliable, affordable power well into the future.
We spent considerable time working with our members preparing for the implementation of a new
rate structure in 2013. Initially approved by the board of directors in 2011, the new wholesale rate
structure is designed to ensure electric co-op consumers, no matter their size, receive an affordable
and equitable wholesale rate for the electricity they use. The new design also allows a more efficient
deployment of our shared assets across our entire network.
A new strategic goal adopted by the board in 2012 targets load growth. We believe there are definite
operational advantages by being larger. However, being larger doesn’t always equate to being better.
The board is taking a measured approach in exploring and analyzing opportunities that may
materialize—whether that’s through supporting our members in promoting their own internal
organic growth, or evaluating external opportunities that would assist us in becoming more efficient while providing lower costs to our members.
More than 60 years ago, our predecessors had the foresight to join together in a cooperative spirit,
in an effort to make themselves more efficient in supplying power to their members and aggregate
the risk to a larger entity. Our core mission remains the same today. Working together, we can successfully navigate our way through the challenges we confront.
It has been an honor to serve another year as president and chairman of the board of directors.
I sincerely thank the board and management for their ongoing support.
Rick Gordon
Chairman
I also want to take this opportunity on behalf of the board, to thank the many dedicated employees
at Tri-State that work tirelessly to make this organization great. Their dedication and commitment
to serve the membership makes Tri-State what it is today.
3
GENERAL
MANAGER’S
MESSAGE
Tri-State’s financial performance was strong in 2012. The association’s margins remained healthy
even with the impact of the strategic acquisition of the Colowyo Mine, which provides long-term
fuel certainty for the association. The acquisition was enabled by the G&T’s solid fiscal footing,
which was affirmed during the year with “A” ratings from the three major rating agencies.
Cooperative Value
The association also recorded solid performance from our generation fleet. In 2012, we completed
the integration of the operations of J.M. Shafer Station, which we acquired in 2011 to serve growing
loads and provide operational flexibility. Even though we experienced an unpredictable, prolonged
outage at our Springerville Generating Station unit, the agility and diversity of our other production assets enabled us to sustain commendable performance.
Tri-State’s vast, four-state power supply network of transmission lines, telecommunications facilities and substations
continued to undergo many reliability improvement projects during the year,
COLLABORATION
including the long-awaited completion in the fall of the 51-mile, Nucla to Sunshine transmission
line in southwestern Colorado, the addition of eight new delivery points for our member systems
and the completion of several fiber optic telecommunications projects.
EQUITY
We added to our renewable resource portfolio in December when 67 megawatts of wind capacity
from the Colorado Highlands Wind project began commercial operation. This new wind facility
is located northeast of Sterling, Colo., in the service territory of Tri-State member co-op Highline
RELIABILITY
Electric Association. In addition to the wind, solar and hydroelectric power that the association
purchases on behalf of our members, the G&T also continues to support the development of local
renewable generation projects sponsored by our member co-ops.
AGGREGATION
In 2013 and beyond,
the electric utility industry faces an increasingly challenging regulatory landscape. Tri-State and other electric utilities that value coal for the production of electricity continue
to deal with uncertainty in regulations aimed at eliminating this affordable resource from the
generation mix. Our
board’s strategic direction is to take appropriate actions to protect our assets,
STEWARDSHIP
preserve our options and enforce our membership’s right to affordable and reliable power.
These efforts include making the investments required to advance technology solutions that protect our membersPRODUCTIVITY
from the risk of carbon regulation. In 2012, the association and our partners
completed a significant geological assessment near our Craig Station that could lead to safely
sequestering carbon underground. We also continue to press for technology solutions that could
capture and utilize carbon for productive uses, and test these and other production and emission
technologies at our facilities.
When necessary, the association has taken legal steps to address regulatory challenges—and
The electric cooperative business model has a long history and proven track record of success. It’s
continues to support educational outreach efforts to inform consumers about the vital role of
an ongoing story of differentaffordable
people and
organizations joining to share resources and work toward
electricity.
common goals on behalf of the co-ops’ member-owners. The primary mission has always been to
Our strong performance in 2012 is testament to the sound governance of our board and the quality
Ken Anderson
produce
and deliver reliable,work
affordable
and responsible
electricity,
while Aligning
enriching
and
enerof our dedicated
and highly competent
employees.
ourlives
human,
capital
and physical
Executive Vice President
and
General
Manager
gizing rural communities and
economies
theofcooperative
value.on our mission.
resources
remainsthrough
at the center
our efforts to deliver
4
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
Tri-State plays an important role in the value chain proposition that is inherent in the cooperative business model. From the mine mouth to the electric socket, the association works
in concert with its 44 member systems to deliver reliable and affordable electricity to the
member-owners whose lives and livelihoods depend on it.
NET MARGINS ($ in millions)
In110
its fundamental role, Tri-State stewards its member systems’
shared
110 generation and transmission assets and manages the
88 of producing or purchasing and then delivering wholesale
risks
88
power
66 to its membership.
NET MARGINS ($ in millions)
106.5
106.5
104.9
104.9
77.1
77.1
69.9
69.9
52.8
52.8
2008
2008
2009
2009
2010
2010
2011
2011
2012
2012
MEMBER CONSUMER-METERS (thousands)
604.7 610.6
592.9 599.4 601.2
610.6
604.7
601.2
592.9 599.4
In66the operation of its 4,238 megawatts of capacity and 5,300
44
miles
44 of high-voltage power lines, Tri-State strives to interact
seamlessly
with its 44 member co-ops in order to operate most
22
22
effectively
and efficiently in a coordinated and collaborative
0
fashion
to advance the collective interests of the 1.5 million
0
member-owners at the end of the line.
As the agent responsible for the members’ collective assets,
Tri-State continually makes investments to strengthen its
generation and transmission network. Efforts were made
in 2012 to integrate the functions of two recently acquired
615
resources
into the G&T’s operations—the Colowyo Mine
615
and
492the J.M. Shafer Generating Station.
492
2008
2008
2009
2009
2010
2010
2011
2011
2012
2012
Tri-State
purchased both these facilities in late 2011 and
369
369
quickly
assimilated them into the G&T’s operations. The
246
northwest
Colorado coal mine ensures a dependable,
246
cost-effective,
long-term fuel source for Tri-State’s nearby
123
Craig
123 Station, while the natural gas-fired, combined cycle
0
272-megawatt
power plant in Fort Lupton, Colo., provides
0
operational flexibility in a high-growth part of its system.
TOTAL MEGAWATT-HOUR SALES (millions)
19.0
19.0
18.6
18.6
18.9
18.9
19.4
19.4
18.7
18.7
20
20
16
16
12
6
2012 ANNUAL REPORT
Numerous improvements to existing Tri-State facilities were made over the course of the past
year. Major upgrades were completed at several of the association’s baseload power plants,
as well as renovations and new construction at some outlying field facilities, increasing the
efficiency, value and life expectancy of these assets.
Transmission improvements also were made aimed at increasing power delivery reliability, most notably the
completion of the Nucla-Sunshine 115-kilovolt line in southwestern Colorado. The new 51-mile line was
constructed over a three-year period; it includes 10 miles of underground power cable, along with 41 miles of
overhead line that runs across rugged mountainous terrain. In addition, the new line and upgraded service
required the construction of two new substations and extensive modifications at two existing substations.
Tri-State also continued to bolster its renewable energy portfolio during the year. The association signed a
20-year power purchase agreement to take delivery of all the electricity generated at the newly commissioned
67-megawatt Colorado Highlands Wind project located within the service territory of member co-op
Highline Electric Association.
The state’s newest wind facility is a joint development between Alliance Power, Inc. and G.E. Energy Financial
Services. It consists of 42 1.6-megawatt General Electric wind turbine generators located on a 5,200-acre
site in northeast Colorado’s Logan County. It can generate enough electricity to serve the equivalent power
needs of approximately 19,000 electric co-op member homes.
The number of member co-op local renewable projects also continued to flourish, assisted through the
support and financial incentives provided under Tri-State board policies. The projects include a variety of
community solar developments and a number of different small hydro applications throughout the region.
Cumulatively, the local projects that have come on-line over the past three years add up to 25 megawatts of
renewable energy.
Tri-State continued to provide value to its member systems through the long-standing, highly successful
Energy Efficiency Products program, which encourages and rewards member-owners to use electricity
wisely through the purchase and installation of energy-efficient appliances, lighting and heating and cooling
systems. That program—first launched in the mid-1980s—paid member-owners more than $1.3 million
in 2012 while reducing their cumulative energy use by approximately 117,000 megawatt-hours.
7
592.9
599.4
601.2
604.7
615
20
TRI-STATE
610.6GENERATION AND TRANSMISSION ASSOCIATION
492
19.0
18.6
18.9
19.4
18.7
16
369
12
Ensuring collective success
and providing significant value
246
8
123
4
0
2008
2009
2010
2011
2008
18.6
18.9
19.4
2009
2010
2011
2012
MEMBER COINCIDENT PEAK DEMAND (megawatts)
19.0
0
2012
20
18.7
16
3000
2,498
2,447
2,568
2,654
2,798
2250
12
1500
8
750
4
0
2008
2009
2010
2011
0
2008
2012
2009
2010
2011
2012
MEMBER COINCIDENT PEAK DEMAND (megawatts)
Along with the utility-oriented products and services it provides, Tri-State also strives to support its member
3000 regularly collaborates with its member co-ops
systems in an assortment of other arenas. The association
TOTAL OPERATING REVENUE ($ in millions)
2,798
and industry related organizations
2,654 in providing educational opportunities to member-owners, community
2,498 2,447 2,568
1300
2250
leaders, legislators and other decision makers.
1,257
1,161
1,164
1,212
1,179
1040
Tri-State continues to pursue technology solutions that
1500can increase efficiency, address costs and manage
regulatory risks. These efforts include leveraging research relationships with other organizations, advancing 780
its internal capacity and supporting new technology approaches,
including the opportunity to utilize carbon
750
520
emissions to manage the increasing risk of carbon regulation.
0
Under its
board’s
direction,
Tri-State
is2012
proactively addressing
the challenges of planning for long-term
2008
2009
2010
2011
resources, addressing increasing regulation and ensuring affordable electricity.
2010
2011
2012
These efforts include the ongoing regional affordability campaign2008that is2009
supported
by Tri-State,
its members
and the four statewide cooperative associations in Colorado, Nebraska, New Mexico and Wyoming. The
initiative is designed to educate key audiences on energy issues and related activities—such as proposed
TOTAL OPERATING
REVENUE
($ in millions)
unreasonable
and unnecessary
regulations—that
threaten thePATRONAGE
cooperatives’
ability to provide affordable power.
CAPITAL RETIREMENTS ($ in millions)
260
0
1300
One such proposal at which Tri-State1,257
took direct action on in 2012 is the Utility MACT (Maximum
1,212 1,179
1,164 Technology
1,161 Control
Achievable
Standard) rule, one1040
of the most20.0
expensive regulatory
programs
in history— 20
20.0
20.0
with estimated costs adding up to billions of dollars annually.
780
Tri-State staff provided Congressional testimony on the rule and the association also filed a legal challenge
(along with more than 30 other organizations and 24520
states) asking a federal
10.0 appeals court to review
10.0 the
rule, which is not believed to be lawful under the Clean
Air Act. The action resulted in the EPA’s reconsid260
eration of the MACT rule for new generating units.
0
Tri-State
will continue
its efforts
in protecting
the interests of the membership and the significant invest2008
2009
2010
2011
2012
2008
2009
2010
2011
2012
ments made in their shared assets, while providing information and education about the myriad risks and
challenges facing the electric utility industry.
Tri-State’s
successful history of delivering safe, reliable and affordable power to its member systems spans
PATRONAGE CAPITAL RETIREMENTS ($ in millions)
more than six decades. Working in collaboration, both the G&T and its member systems become stronger
while ensuring collective success and providing significant
20 value to the member-owners.
20.0
20.0
20.0
15
10.0
10.0
10
8
15
10
5
0
2012 ANNUAL REPORT
BOARD OF
DIRECTORS
Rick Gordon
Tony Casados
Jim Soehner
Stuart Morgan
Bill Bird
Chairman
Mountain View Electric
Vice Chairman
Northern Rio Arriba Electric
Secretary
Y-W Electric
Treasurer
Wheat Belt Public Power
Assistant Secretary
Otero County Electric
Wayne Child
Marshall Collins
Jack Finnerty
Gary Merrifield
Leroy Anaya
Assistant Secretary
High West Energy
Executive Committee
Delta-Montrose Electric
Executive Committee
Wheatland Rural Electric
Executive Committee
Sangre de Cristo Electric
Socorro Electric
Jimmy Bason
Robert Bledsoe
Leo Brekel
Matt Brown
Richard Clifton
Sierra Electric
K.C. Electric
Highline Electric
High Plains Power
Carbon Power & Light
As a wholesale power cooperative, Tri-State is owned and governed by its 44 member distribution
systems, with the Board of Directors comprised of one representative from each of its members.
Each director is appointed by his or her local co-op to the Tri-State board, with terms normally
running one year from April to April (coinciding with the G&T’s annual meeting).
The Tri-State board, which meets on a monthly basis, also is divided into four committees—
the Executive Committee (consisting of the six officers of the board along with three at-large
positions), the Engineering and Operations Committee, the Finance Committee and the External
Affairs/Member Relations Committee.
9
BOARD OF
DIRECTORS
Wayne Connell
Elias Coriz
Ron Hagan
Jack Hammond
Ralph Hilyard
Central New Mexico Electric
Jemez Mountains Electric
Midwest Electric
Niobrara Electric
Roosevelt Public Power
Don Keairns
Hal Keeler
Thaine Michie
William Mollenkopf
Chris Morgan
San Isabel Electric
Columbus Electric
Poudre Valley Rural Electric
Empire Electric
Gunnison County Electric
Richard Newman
James “Wes” Perrin
Gary Rinker
Art Rodarte
Claudio Romero
United Power
San Miguel Power
Southwestern Electric
Kit Carson Electric
Continental Divide Electric
Ken Anderson
Joel Bladow
Pat Bridges
Mike M cInnes
Brad Nebergall
Executive Vice President
General Manager
Senior Vice President
Transmission
Chief Financial Officer
Production
Energy Management
SENIOR
MANAGEMENT
10
2012 ANNUAL REPORT
Daniel Romero
Don Russell
Brian Schlagel
Gerald Seward
Mora-San Miguel Electric
Big Horn Electric
Morgan County Rural
Electric
Springer Electric
J.H. Sheridan
Kevin Stuart
Carl Trick, Jr.
Jerry Thompson
White River Electric
Chimney Rock Public Power
Mountain Parks Electric
Garland Light & Power
Joe Wheeling
Scott Wolfe
F.E. “Wally” Wolski
Bill Wright
La Plata Electric
San Luis Valley Electric
Wyrulec Co.
Southeast Colorado Power
Ken Reif
Jim Spiers
Lowell Stave
Barbara Walz
General Counsel
Business Strategy/
Chief Technology Officer
Member Relations
Policy and Compliance/
Chief Compliance Officer
11
123
0
2008
2009
2010
2011
0
2012
2008
FINANCIAL HIGHLIGHTS
& FIVE-YEAR
FINANCIAL
SUMMARY
MEMBER CONSUMER-METERS
(thousands)
2009
2010
2011
2012
615
20
by an uncertain economy, a persistent drought and a prolonged outage at our Springerville
492
16
369million margin in 2012 provided a debt service
Generating Station unit. Tri-State’s $52.8
12
coverage well in excess of the requirement
246 in its Master First Mortgage Indenture and
8
604.7
610.6
592.9 599.4
19.4presented
Tri-State
had a 601.2
good year from a financial perspective in spite
the challenges
19.0 of 18.6
18.9
18.7
helped grow the association’s equity as a percentage of total capitalization to 23.5 percent.
123
0
at the Springerville Generating Station because of a three2008
2009
2010
2011
2012
month outage to repair a damaged turbine, which resulted
in a $13.3 million decrease in 2012 non-member electric
sales revenue from Unit 3 as compared to 2011. Despite
these decreases,
the COINCIDENT
2012 non-member
sales
revenue
MEMBER
PEAK electric
DEMAND
(megawatts)
increased $9.9 million over 2011’s revenue to $162.7 million
due primarily to the 2012 recognition of $10.0 million of
2,798
previously deferred 2007 non-member sales
revenue
and
2,568 2,654
2,498
2,447 electric sales revenue was
the fact that 2011
non-member
reduced by a $55 million revenue deferral. The $55 million
revenue deferral will be recognized at the discretion of
Tri-State’s board of directors over the next five years.
Tri-State
continues
to2010
maintain
its strong
liquidity. As of
2008
2009
2011
2012
December 31, 2012, Tri-State had $81.5 million in cash, $75
million of unused committed lines of credit and a secured
revolving credit facility with a total unused commitment of
$387 million.
Consistent with the principles of a financially healthy coop20
erative,
Tri-State declared a $10
million patronage capital
19.4
19.0
18.9
18.7
18.6
refund to its members during 2012, which makes this the
16
24th consecutive year that the association has returned
capital credits.
12
Through the challenges, Tri-State has continued to maintain
8
it’s A rating from the three major rating agencies, which is
a tribute to the decision making of our board of directors 4
and staff.
Purchased power expense increased $37.0 million, or 13.5
percent, to $310.3 million in 2012. This increase was due
to a 6.6 percent increase in megawatt-hours purchased and a
7.6 percent increase
average2010
cost of purchased
power.
2008 in the
2009
2011
2012
The 2011 average cost was lower primarily due to the high
availability of low cost hydroelectric power in 2011. This
favorable situation did not repeat itself in 2012 due to this
year’s drought.
Tri-State continues to invest in its infrastructure through0
2008
2009
2010
2011
2012
capital improvements and system upgrades in order to
serve the growing needs of its member distribution systems.
Electric plant in service increased $205.1 million from
December
31, 2011 toPEAK
$4.857
billion as
of December 31, 2012.
MEMBER
COINCIDENT
DEMAND
(megawatts)
Lease expense decreased $12.7 million, or 65.3 percent, to
$6.7 million in 2012. This decrease was primarily due to the
December 2011 acquisition of the 272-megawatt combined
cycle J.M. Shafer Generating
Station.
to the 1,257
acquisi1,212 Prior
1,179
1,161 1,164
tion, Tri-State leased 150 megawatts of the station under
a gas tolling arrangement. Subsequent to the acquisition,
Tri-State owns the station and therefore does not have the
lease expense in 2012.
The association provides power to its member systems3000
and
also sells power to other utilities in the
region
under
long2,798
2,568 2,654
term
contracts
2,498
2,447and market sale arrangements. Member
2250
electric sales for 2012 reached a new record 15,717,468
megawatt-hours which was 1.9 percent greater than 2011’s
1500
record setting 15,421,227 megawatt-hours. Member electric
sales revenue increased $59.1 million, or 5.9 percent, due to
750
this increase in sales and the 4.8 percent rate increase effective January 1, 2012.
Despite the general economic and specific business challenges, Tri-State continues to be financially strong, creditworthy and prepared to meet the future needs of the member
distribution systems and their consumer-owners.
The 2012 non-member electric sales decreased 966,570 0
2008
2009
2010
2011
2012
megawatt
hours,
or 24.3
percent.
Almost
half of this decrease
was due to reduced firm contractual sales out of our Unit 3
2008
1,161
1,164
1,212
1,179
1,257
2009
2010
2011
20.0
1040
20.0
1500
750
0
1300
1040
780
520
260
0
15
10.0
10.0
10
5
0
0
2011
2250
20
20.0
260
2010
3000
PATRONAGE CAPITAL RETIREMENTS ($ in millions)
1300
520
2009
0
2012
780
2008
4
2008
2012
12
2009
2010
2011
2012
2012 ANNUAL REPORT
2012
2011
2010
2009
2008
$1,067,085
189,911
$1,007,993
168,187
$981,126
231,290
$926,428
237,468
$869,960
290,678
(Thousands)
Operating revenues
Member
Non-member
Operating expenses
Power costs
Lease expense
Transmission
General and administrative
Depreciation and amortization
Income taxes
Operating margins
Other income
Other deductions
Interest expense
Other expenses
(797,576)
(6,714)
(136,853)
(22,810)
(115,314)
—
(727,185)
(19,365)
(136,825)
(18,930)
(105,793)
10
(728,735)
(22,711)
(121,786)
(18,694)
(131,739)
9,738
(669,590)
(71,115)
(115,128)
(16,514)
(104,973)
(7,615)
(703,047)
(64,991)
(106,578)
(11,589)
(98,936)
(1,954)
177,729
30,890
168,092
64,164
198,489
32,297
178,961
28,739
173,543
36,173
(150,248)
(8,618)
(154,291)
(11,844)
(147,243)
(11,138)
(97,560)
(5,476)
(97,567)
(5,700)
$66,121
3,813
$72,405
4,739
$104,664
210
$106,449
—
$52,795
$69,934
$2,926,700
152,355
$2,819,499
183,178
$77,144
$104,874
$106,449
$2,696,137
201,011
$2,661,633
133,111
$1,596,339
143,861
3,079,055
3,002,677
2,897,148
2,794,744
1,740,200
Cash and cash equivalents
Restricted cash and investments
Accounts receivable
Inventories
Other current assets
81,492
27,143
133,401
132,612
19,193
117,507
—
120,527
119,214
17,985
205,452
—
115,104
94,185
17,098
145,585
—
112,243
101,586
16,323
85,873
—
104,177
75,474
13,880
Total current assets
393,841
375,233
431,839
375,737
279,404
Investments in other associations
Prepaid lease expense
Investments in securities pledged as collateral
Goodwill and intangible assets
Other assets
121,938
—
35,146
35,881
144,403
492,303
117,211
—
44,793
—
155,221
495,838
113,436
—
—
—
—
351,732
110,368
—
—
—
—
407,906
105,917
90,202
—
—
—
295,526
Total other assets
829,671
813,063
465,168
518,274
491,645
Total assets
$4,302,567
$4,190,973
$3,794,155
$3,688,755
$2,511,249
Long-term debt
Current liabilities
Deferred credits and APBO
$2,790,368
390,807
202,483
$2,712,152
390,352
209,014
$2,491,538
325,690
143,137
$2,509,129
263,135
134,203
$1,571,793
268,462
113,506
Net margins including noncontrolling interest
Net loss attributable to noncontrolling interest
$49,753
3,042
Net margins attributable to the Association
Plant in service (net)
Construction work in progress
Total plant
Total liabilities
3,383,658
3,311,518
2,960,365
2,906,467
1,953,761
Patronage capital equity
Noncontrolling interest
805,882
113,027
763,335
116,120
713,807
119,983
652,613
129,675
557,488
—
Total equity
918,909
879,455
833,790
782,288
557,488
Total equity and liabilities
$4,302,567
$4,190,973
$3,794,155
$3,688,755
$2,511,249
Other data:
Megawatt-hours sold—member
—non-member
System coincident peak demand—megawatts
Average member mills/kWh—sales
Average member mills/kWh—capital refunds
Plant additions (cash)
Capital credit allocations received
Tri-State capital credits retired
Long-term debt repaid
Weighted average long-term debt interest rate
Equity as a % of total capitalization
15,717,468
3,010,314
2,798
67.89
0.64
$195,895
7,845
10,000
416,780
5.2%
23.5%
15,421,227 15,026,510 14,245,565 14,028,575
3,976,884
3,836,646
4,311,891
4,979,993
2,654
2,568
2,447
2,498
65.36
64.98
65.03
62.01
1.30
1.33
0.70
1.43
$145,446 $232,805 $298,791 $116,208
7,167
6,162
12,712
19,252
20,000
20,000
10,000
20,000
142,767
220,466
171,141
124,636
5.7%
5.7%
5.9%
5.7%
23.3%
24.0%
22.9%
24.6%
13
Report of Independent Auditors
The Board of Directors of Tri-State Generation and Transmission Association, Inc.
Report on the Financial Statements
We have audited the accompanying consolidated financial statements of Tri-State Generation and Transmission Association, Inc. (the Association)
which comprise the consolidated statements of financial position as of December 31, 2012 and 2011, and the related consolidated statements
of operations, comprehensive income, equity, and cash flows for each of the three years ended December 31, 2012, and the related notes to the
consolidated financial statements.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated 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 consolidated 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 consolidated 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.
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 consolidated financial position of Tri-State
Generation and Transmission Association, Inc. at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows
for the three 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 have also issued our report dated February 22, 2013 on our consideration of the
Association’s internal control over financial reporting and on our tests of its compliance with certain provisions of laws, regulations, contracts,
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 the Tri-State Generation
and Transmission Association, Inc.’s internal control over financial reporting compliance.
Denver, Colorado
February 22, 2013
14
2012 ANNUAL REPORT
Consolidated Statements of Financial Position
As of December 31, (Thousands)
ASSETS
Electric plant
In service
Total electric plant
Less allowances for depreciation and amortization
2012
2011
$4,856,572
152,355
$4,651,484
183,178
5,008,927
(1,929,872)
4,834,662
(1,831,985)
3,079,055
3,002,677
121,938
170,949
35,146
35,881
7,796
144,403
11,159
117,211
168,002
44,793
—
7,772
155,221
13,810
Total other assets and investments
Current assets
Cash and cash equivalents
Deposits and advances
Accounts receivable—members
Other accounts receivable
Coal inventory
Materials and supplies
527,272
506,809
81,492
27,143
19,193
86,651
46,750
61,254
71,358
117,507
—
17,985
82,878
37,649
54,313
64,901
Total current assets
Deferred charges
393,841
302,399
375,233
306,254
Total assets
$4,302,567
$4,190,973
EQUITY AND LIABILITIES
Capitalization
Patronage capital equity
Noncontrolling interest
$805,882
113,027
$763,335
116,120
Total patronage capital equity and noncontrolling interest
Long-term debt
918,909
2,790,368
879,455
2,712,152
Total capitalization
Current liabilities
Member advances
Accounts payable
Accrued expenses
Current maturities of long-term debt
3,709,277
3,591,607
14,477
93,969
84,308
198,053
15,862
83,460
105,975
185,055
390,807
199,304
3,179
390,352
205,915
3,099
$4,302,567
$4,190,973
Net electric plant
Other assets and investments
Investments in coal mines
Investment in securities pledged as collateral
Deferred equity note
Goodwill and intangible assets
Other noncurrent assets
Total current liabilities
Deferred credits and other liabilities
Accumulated postretirement benefit and postemployment obligations
Total equity and liabilities
The accompanying notes are an integral part of these consolidated statements.
15
Consolidated Statements of Operations
For the years ended December 31, (Thousands)
Operating revenues
Member electric sales
Non-member electric sales
Other
Operating expenses
Purchased power
Fuel
Production
Lease expense
Transmission
General and administrative
Generation maintenance
Transmission maintenance
Income taxes
2012
2011
2010
$1,067,085
162,694
27,217
$1,007,993
152,806
15,381
$981,126
208,357
22,933
1,256,996
1,176,180
1,212,416
310,293
273,609
108,925
6,714
112,006
22,810
104,749
24,847
115,314
—
Operating margins
Other income
Interest income
Capital credits from cooperatives
Other income (loss)
Interest and other deductions
Interest expense, net of amounts capitalized
Other deductions
16
273,287
265,917
105,593
19,365
111,795
18,930
82,388
25,030
105,793
(10)
263,806
258,767
108,067
22,711
102,805
18,694
98,095
18,981
131,739
(9,738)
1,079,267
1,008,088
1,013,927
177,729
168,092
198,489
23,662
7,845
(617)
27,065
7,167
29,932
20,932
6,162
5,203
30,890
64,164
32,297
150,248
8,618
154,291
11,844
147,243
11,138
158,866
166,135
158,381
49,753
3,042
$52,795
66,121
3,813
$69,934
72,405
4,739
$77,144
2012 ANNUAL REPORT
Consolidated Statements of Comprehensive Income
Other comprehensive income:
Unrealized gain (loss) on securities available for sale
Unrecognized actuarial gain on postretirement benefit obligation
Less: Reclassification adjustment for actuarial gain on postretirement
benefit obligation included in net income
Income tax expense related to components of other comprehensive income
Other comprehensive income
Comprehensive income including noncontrolling interest
Net comprehensive loss attributable to noncontrolling interest
Comprehensive income attributable to the Association
2012
2011
2010
$49,753
$66,121
$72,405
109
—
(48)
—
144
4,152
(357)
—
(358)
—
—
—
(248)
(406)
4,296
49,505
3,042
$52,547
65,715
3,813
$69,528
76,701
4,739
$81,440
2011
2010
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Equity
2012
Patronage capital equity at beginning of year
Other comprehensive income
Retirements
Reduction attributable to acquisition of noncontrolling interest
$763,335
52,795
(248)
(10,000)
—
Patronage capital equity at end of year
805,882
Noncontrolling interest at beginning of year
Equity distribution to noncontrolling interest
Noncontrolling interest acquired by the Association
$116,120
(3,042)
(51)
—
Noncontrolling interest at end of year
Total patronage capital equity and noncontrolling interest at end of year
17
$713,807 $652,613
69,934
77,144
(406)
4,296
(20,000)
(20,000)
—
(246)
763,335
713,807
$119,983 $129,675
(3,813)
(4,739)
(50)
(51)
—
(4,902)
113,027
116,120
119,983
$918,909
$879,455
$833,790
Consolidated Statements of Cash Flows
Operating activities
Adjustments to reconcile net margins to net cash provided by operating activities:
Capital credit allocations from cooperatives and income from
coal mines over refund distributions
Recognition of deferred revenue
Deferred revenue
Changes in operating assets and liabilities:
Accounts receivable
Coal inventory
Materials and supplies
Accounts payable and accrued expenses
Change in restricted cash and investments
Other
Net cash provided by operating activities
Investing activities
Purchases of plant, net of retirements
Acquisition of Thermo Cogeneration Partnership
Acquisition of Colowyo Coal
Changes in deferred charges
Changes in other noncurrent assets
Net cash used in investing activities
Financing activities
Member advances
Payments of long-term debt
Advance payments to RUS and funds on deposit with trustees
Retirement of patronage capital
Proceeds from issuance of debt
Change in restricted cash and investments
Securities pledged as collateral—defeasance of Colowyo Bonds
Proceeds from investment in securities pledged as collateral
Net cash provided by (used in) financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents—beginning
2012
2011
2010
$49,753
$66,121
$72,405
115,314
105,793
131,739
(11,217)
(10,000)
—
(5,404)
(10,000)
55,000
(4,112)
(5,599)
—
(12,868)
(6,941)
(6,457)
(3,181)
(30,380)
10,662
4,397
(4,156)
(551)
862
—
(2,968)
(2,830)
10,059
(2,565)
30,849
—
10,741
94,685
209,094
240,687
(195,895)
—
—
6,391
2,707
(145,446)
(204,260)
(108,069)
(79)
1,301
(232,805)
—
—
62,337
1,237
(186,797)
(456,553)
(169,231)
(1,385)
(416,780)
123,115
(14,869)
390,177
(32,644)
—
8,483
7,563
(142,767)
84,115
(14,779)
270,175
—
(44,793)
—
(240)
(220,466)
(337,309)
(15,792)
562,218
—
—
—
56,097
159,514
(11,589)
(36,015)
117,507
(87,945)
205,452
59,867
145,585
Cash and cash equivalents—ending
$81,492
$117,507
$205,452
Supplemental information:
Cash paid for interest
$142,375
$130,335
$105,721
18
2012 ANNUAL REPORT
Notes to Consolidated Financial Statements
Note 1—Organization
Tri-State Generation and Transmission Association, Inc. (the “Association”) is a wholesale power supply cooperative. During 2012, it provided
power to 44 member distribution systems that serve major parts of Colorado, Nebraska, New Mexico and Wyoming. The Association also
sells a portion of its power to other utilities in the region under long-term contracts (see Note 12—Commitments and Contingencies) and
market sale arrangements. In 2012, 2011 and 2010, total megawatt-hours sold were 18.7, 19.4 and 18.9 million, respectively, of which 84, 79
and 80 percent, respectively, were sold to members. Total revenue from electric sales was $1.2 billion for each of the years 2012, 2011 and 2010
of which 87, 87 and 82 percent, respectively, were from member sales. Energy resources were provided by generation and purchased power, of
which 62, 65 and 67 percent were from generation for 2012, 2011 and 2010, respectively.
The Association has wholesale power contracts with 42 of its members through the year 2050 and with 2 of its members through the year
2040 whereby each member is obligated to purchase at least 95 percent of its requirements from the Association and can elect to provide up
to 5 percent of its requirements from generation owned or controlled by the member. Nine members have made such an election. Power is
provided to members at rates determined by the Board of Directors. Rates are designed to recover all costs and provide margins to increase
members’ equity.
Undivided interests in the jointly owned facilities of the Yampa Project, the Missouri Basin Power Project (“MBPP”), and the San Juan Project
(“San Juan”) are owned by the Association. Each participant in these facilities provides its own financing. The Association receives a portion
of the total output of the generating stations, which approximates its percentage ownership. The operating agent for each of these projects
allocates to the Association its share of fuel and other operating costs.
The Association, including its subsidiaries, employs 1,517 people, of which 354 are subject to collective bargaining agreements. None of these
agreements expire within one year.
Note 2—Summary of Significant Accounting Policies
Basis of Consolidation:
The consolidated financial statements include the accounts of the Association and its 99 percent interest in Western Fuels-Colorado, a limited
liability company organized for the purpose of acquiring coal reserves and supplying coal to the Association. The consolidated financial statements also include, on a pro rata basis, the Association’s undivided interests in jointly owned facilities (see Note 1—Organization), entities
acquired by the Association that are accounted for as business combinations and the Association’s acquisition of the Springerville Unit 3
Partnership assets (see Note 3—Acquisitions). All significant intercompany balances and transactions have been eliminated in consolidation.
The accompanying consolidated statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”)
as applied to regulated enterprises and as prescribed by the Rural Utilities Service (“RUS”).
Business Combinations:
The Association accounts for business acquisitions by applying the accounting standard related to business combinations (see Note 3—
Acquisitions). In accordance with this method, the identifiable assets acquired, the liabilities assumed and any noncontrolling interests in the
acquired entities are required to be recognized at their acquisition date fair values. The Association typically engages an independent valuation
firm to determine the acquisition date fair values of most of the acquired assets and assumed liabilities. The excess of total consideration transferred over the net assets acquired is recognized as goodwill. Acquisition related costs such as legal fees, accounting services fees and valuation
fees, are expensed as incurred. The Association is required to consolidate these acquired entities. If an acquisition does not result in acquiring
a business, the transaction is accounted for as an acquisition of assets. This method requires measurement and recognition of the acquired net
assets based upon the amount of cash transferred and the amount paid for acquisition-related costs. There is no goodwill recognized in an
acquisition of assets.
Use of Estimates:
The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities, 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 may differ from those estimates.
19
Electric Plant and Depreciation:
Electric plant is stated at cost. The cost of internally constructed assets includes payroll, overhead costs and interest charged during construction.
Interest rates charged during construction of 5.4, 5.4 and 5.5 percent were used for 2012, 2011 and 2010, respectively. The amount of interest
capitalized during construction was $15.2, $13.6 and $13.0 million during 2012, 2011 and 2010, respectively. At the time that units of electric
plant are retired, original cost and cost of removal, net of the salvage value, are charged to the allowance for depreciation. Replacements of
electric plant that involve less than a designated unit value are charged to maintenance expense when incurred. Electric plant is depreciated
based upon estimated depreciation rates and useful lives that are periodically re-evaluated. Effective January 1, 2011, the Association adopted
depreciation rates that reflect rates determined in depreciation rate studies performed and completed during 2011 for most of the Association’s
generating stations. These new rates resulted in a reduction in 2011 depreciation expense of $32.8 million compared to the depreciation
expense that would have resulted from using prior rates.
Leases:
The accounting for lease transactions in conformity with GAAP requires management to make various assumptions, including the discount
rate, the fair market value of the leased assets and the estimated useful life, in order to determine whether a lease should be classified as operating
or capital.
The Association has certain power sales arrangements that are required to be accounted for as operating leases since the arrangements are
in substance leases because they convey the right to use power generating equipment for a stated period of time. The contracts under which
sales are made to Public Service Company of Colorado (“PSCO”) out of the Association’s Knutson and Limon Generating Stations are such
arrangements. Under these contracts, PSCO directs the use of both of the two Knutson generating units and one of the two Limon generating
units over the terms of the contracts under tolling arrangements whereby PSCO provides its own natural gas for generation of electricity. The
arrangements are therefore accounted for as operating leases. The Limon contract was suspended for a period of four years beginning in May
2009 and the Knutson contract was suspended for a period of three years beginning in May 2010 to allow the Association to utilize the output
of the turbines. Both turbine contracts resume with PSCO under the original tolling arrangements for the period May 1, 2013 to April 30,
2016. The Association also has similar tolling arrangements involving the Association’s Pyramid Generating Station. One arrangement involved
a 40 megawatt unit under a three month contract during 2010 and another involves a 40 megawatt unit under a contract with Shell Energy
North America through September 30, 2014. On December 2, 2011, the Association acquired Thermo Cogeneration Partnership in a business
combination (see Note 3—Acquisitions) and thereby acquired the J.M. Shafer Generating Station (formerly known as the Fort Lupton Gener
ating Station) from which PSCO is purchasing power under a tolling arrangement that is similar to the above arrangements and is therefore
also accounted for as an operating lease by the Association. The revenues from these operating leases of $13.2, $1.8 and $7.9 million for 2012,
2011 and 2010, respectively, are accounted for as lease revenue and are reflected in other operating revenue on the statements of operations. The
generating units used in these gas tolling arrangements have a total cost and accumulated depreciation of $228 and $100 million, respectively,
as of December 31, 2012 and of $226 and $95.4 million, respectively, as of December 31, 2011.
The minimum future lease revenues under these gas tolling arrangements at December 31, 2012 are as follows (thousands):
2013
2014
2015
2016
2017
Thereafter
$ 25,691
33,012
32,563
18,542
11,533
17,298
$138,639
The Association has entered into power purchase arrangements that are required to be accounted for as operating leases since the arrangements
are in substance leases because they convey to the Association the right to use power generating equipment for a stated period of time. One
such agreement began in June 2008 and ended May 2012 for the use of generating equipment at the Rawhide Generating Station (owned
by Platte River Power Authority). Additionally, two agreements began in 2009 that give the Association the use of generating equipment at
the J.M. Shafer Generating Station (owned by Thermo Cogeneration Partnership) and at the Brush Generating Station (owned by Brush
Cogeneration Partners). Under these agreements, the Association directs the use of the contracted generating equipment over the terms of
the contracts under tolling arrangements whereby the Association provides its own natural gas for generation of electricity. These tolling
arrangements are discussed further in Note 9—Leases. On December 2, 2011, the Association acquired Thermo Cogeneration Partnership
in a business combination which thereby resulted in the elimination of the J.M. Shafer Generating Station agreement as of this date
(see Note 3—Acquisitions).
20
2012 ANNUAL REPORT
Investments in Other Associations:
Investments in other associations primarily include the Association’s investment in the patronage capital of other cooperatives. Allocations of
capital credits from other cooperatives are based on the Association’s patronage with the cooperatives. Cash retirements of capital credits from
other cooperatives reduce the investment balances. Investments in other associations are as follows (thousands):
2012
2011
Basin Electric Power Cooperative
National Rural Utilities Cooperative Finance Corporation
CoBank, ACB
Western Fuels Association
Other
$69,829
42,873
4,597
1,777
2,862
$64,310
43,905
4,319
1,976
2,701
$121,938
$117,211
Investments in Coal Mines:
The Association owns 99 percent of Western Fuels-Colorado which is the owner and operator of the New Horizon Mine near Nucla, Colorado.
In addition, on December 2, 2011, Western Fuels-Colorado acquired Colowyo Coal Company which owns the Colowyo Mine, a large surface
coal mine near Craig, Colorado. See Note 3—Acquisitions for a further discussion of this acquisition. In addition, the Association has partial
ownership in Western Fuels Association (“WFA”), which, through its ownership in Western Fuels-Wyoming, is the owner and operator of the
Dry Fork Mine near Gillette, Wyoming. The Association also owns a 50 percent undivided ownership in the land and the rights to mine the
property known as Fort Union Mine which is located adjacent to the Dry Fork Mine. The Association and certain participants in the Yampa
Project are members of Trapper Mining, Inc. (“Trapper Mining”) which is organized as a cooperative and is the owner and operator of the
Trapper Mine near Craig, Colorado. Investments in coal mines are as follows (thousands):
2012
2011
Colowyo Mine
Trapper Mine
New Horizon Mine
Dry Fork Mine
Fort Union Mine
$135,909
12,747
18,473
1,791
2,029
$138,799
12,215
12,002
3,062
1,924
Investments in coal mines
$170,949
$168,002
Deferred Equity Note:
During 1981 and 1982, the Association sold certain tax benefits under the safe harbor leasing provision of the Internal Revenue Code. The
initial proceeds were recorded in deferred credits and are being amortized into income at $715,000 per year through 2024. The unamortized
balance at December 31, 2012 and 2011 was $8.3 and $9.0 million, respectively. The 1981 lease included a $34.7 million deferred equity note,
payable annually, that has a balance of $7.8 million at December 31, 2012 and 2011.
Cash and Cash Equivalents:
The Association considers highly liquid investments with an original maturity of three months or less to be cash equivalents.
Restricted Cash and Investments:
Restricted cash and investments represent funds designated by the Association’s Board of Directors for specific uses and funds restricted
by contract or other legal reasons. A portion of the funds is for the payment of debt within one year and is therefore a current asset on the
statements of financial position. The other funds are noncurrent and are included in other assets and investments.
21
Marketable Securities:
The Association’s investment in fixed maturity securities is classified as either held-to-maturity, available-for-sale or trading. Investments in
debt securities that the Association has both the positive intent and ability to hold to maturity are carried at amortized cost. Investments in
debt securities that the Association does not have the positive intent and ability to hold to maturity are classified as available-for-sale or trading
and are carried at fair value. Classification of debt securities is made at the time of purchase and, prospectively, that classification is reevaluated
as of each balance sheet date. Unrealized holding gains and losses on securities classified as available-for-sale are carried as a separate component
of members’ equity. Unrealized holding gains and losses on securities classified as trading would be reported in margins. The Association
does not have any such investments. Realized gains and losses on sales of investments, and declines in value judged to be other-than-temporary,
are recognized on the specific identification basis. Net realized gains are included in other income and net realized losses are included in
other deductions.
The Association holds marketable securities in connection with the directors’ and executives’ elective deferred compensation plans which
consist of investments in stock funds, bond funds and money market funds. At December 31, 2012, the cost and estimated fair value of the
investments based upon their active market value were $1.3 and $1.3 million, respectively, with a net unrealized loss balance of $22,000. At
December 31, 2011, the cost and estimated fair value of the investments were $1.4 and $1.3 million, respectively, with a net unrealized loss
balance of $131,000. The estimated fair value of the investments is included in other noncurrent assets on the statements of financial position.
The change in the net unrealized gain or loss is reported separately as a component of comprehensive income as shown on the statements of
comprehensive income.
The Association holds marketable securities to maturity in connection with the December 2011 defeasance of the Colowyo Bonds. These
consist of U.S. treasuries in the amount of $33.5 million at December 31, 2012 and $42.0 million at December 31, 2011 which are included in
investment in securities pledged as collateral on the statements of financial position. This is discussed further in Note 6—Long-Term Debt.
Derivatives:
The Association is exposed to certain risks in the normal course of operations in providing a reliable and affordable source of wholesale electricity to the member distribution systems. These risks include commodity price risk which represents the risk of loss due to changes in market
prices that may impact the Association’s financial performance. To manage this exposure, the Association has entered into physically-delivered
forward commodity contracts of various durations. These contracts are evaluated in accordance with the accounting guidance for derivative
instruments and hedging activities. To the extent that the contracts are considered derivatives, the Association assesses whether or not the
normal purchase or normal sale exception applies. For contracts that this exception cannot be applied, the accounting guidance for derivative
instruments and hedging activities requires recognition of all qualifying derivative instruments as either assets or liabilities on the statements
of financial position and measurement of those instruments at fair value. Furthermore, the accounting guidance requires that changes in the
fair value of derivatives are to be recorded in current earnings if the instrument is not designated as a hedge.
The Association has entered into certain forward purchase agreements for the future delivery of natural gas in order to ensure an adequate supply
of natural gas at a price certain for the generation of electricity. These fixed-price, fixed-quantity physical contracts are considered derivative
instruments and are recorded at fair value. The valuation assumptions utilized to measure the fair value of these commodity derivatives were
observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets,
liabilities (adjusted) and market-corroborated inputs). Specifically, the fair value is based upon actively quoted prices in the gas market. Hedge
accounting treatment has not been elected for the natural gas agreements.
The natural gas futures contracts outstanding at December 31, 2011 (for delivery of natural gas in 2012) had a fair value that was $772,000
below their fixed contract prices and these were recorded in deferred credits and other liabilities. The outstanding natural gas futures contract
at December 31, 2010 (for delivery of natural gas in 2011) had a fair value that was $239,000 above its fixed contract price and this was recorded
in deferred charges. The gain and loss resulting from the changes in fair value of the derivatives would ordinarily have been recorded in fuel
expense. However, the current recognition of the mark to market gain and loss was deferred under the accounting requirements related to
regulated operations (see Note 2—Accounting for Rate Regulation). Under these requirements, a gain is deferred and accounted for as a
regulatory liability rather than as a negative fuel expense. A loss is deferred and accounted for as a regulatory asset rather than as a positive
fuel expense. This accounting results in the deferred derivative mark to market gain/loss recorded as a regulatory liability/asset being equal
to the balance in the corresponding derivative mark to market fair value recorded in deferred charges or deferred credits and other liabilities.
At December 31, 2011, the deferred derivative mark to market loss of $772,000 was recorded as a regulatory asset in deferred charges. At
December 31, 2010, the deferred derivative mark to market gain of $239,000 was recorded as a regulatory liability in deferred credits and
other liabilities. The change in these accounts was included in the operating section of the statements of cash flows.
22
2012 ANNUAL REPORT
Under this regulatory accounting approach, the process of marking the derivatives to market and deferring the recognition of the mark to
market gain/loss continues until each derivative purchase contract is settled. At the time of the delivery/settlement of each derivative contract,
fuel expense is recognized for the amount actually owed under the contract and the derivative contract fair value asset/liability and the
corresponding derivative regulatory liability/asset are eliminated. Therefore, the mark to market accounting never impacts fuel expense. This
regulatory accounting treatment of mark to market gains and losses results in each of the derivative natural gas purchases being recognized as
an expense at delivery/settlement which matches the cost recovery included in the Association’s rates.
The following table summarizes the notional amounts of outstanding natural gas futures contracts with fixed price terms that comprise the
mark to market values as of December 31 (thousands):
Commodity
Natural gas
Unit of Measure
2012 Quantity
2011 Quantity
2012 Contract Price/
MMBTU Low/High
2011 Contract Price/
MMBTU Low/High
MMBTU
—
961
—
$3.495/$4.005
The fair values of the derivative instruments reflected in the consolidated statements of financial position as of December 31 are as follows
(thousands):
Balance Sheet Location
Derivatives in an asset position not
designated as hedging instruments:
Natural gas futures contracts
Derivatives in a liability position not
designated as hedging instruments:
Natural gas futures contracts
2012
2011
Deferred charges
$—
$—
Deferred credits and other liabilities
$—
$772
The following table reconciles the beginning and ending balances of the Association’s net regulatory liability that pertains to the 2010 natural
gas futures contract that was in a net gain position and included in deferred credits and other liabilities (thousands):
2012
2011
Beginning Balance
Changes in fair value recognized in regulatory liability
Eliminated from regulatory liability at contract settlement
$—
—
—
$239
19
(258)
Ending Balance
$—
$—
The following table reconciles the beginning and ending balances of the Association’s net regulatory asset that pertains to the 2011 natural gas
futures contracts that were in a net loss position and included in deferred charges (thousands):
2012
2011
Beginning Balance
Changes in fair value recognized in regulatory asset
Eliminated from regulatory asset at contract settlement
$772
459
(1,231)
$—
772
—
Ending Balance
$—
$772
Certain of the Association’s derivative instruments contain provisions that require the Association’s debt to maintain an investment grade
credit rating from each of the major credit rating agencies. If the Association’s debt were to fall below investment grade, the counterparties to
the derivative instruments could request immediate payment or demand collateralization on derivative instruments in net liability positions.
As of December 31, 2012, the Association’s credit rating was investment grade and therefore no collateral has been required to be posted.
23
Inventories:
Coal inventories of $44.8 and $36.1 million at December 31, 2012 and 2011, respectively, are stated at LIFO (last-in, first-out) cost. The
remaining coal inventories, other fuel, and materials and supplies inventories are stated at average cost.
SO2 Emission Allowances:
The Association has received an annual allocation of SO2 (sulfur dioxide) emission allowances from the Environmental Protection Agency
as part of a nationwide program to limit SO2 emissions. An allowance provides authority to emit one ton of SO2 . Under this program, the
Association has received more SO2 allowances than it has utilized. The unutilized SO2 allowances have no cost basis and are therefore not
recorded on the balance sheet.
Asset Retirement Obligations:
The Association accounts for current obligations associated with the future retirement of tangible long-lived assets in accordance with the
accounting guidance relating to asset retirement and environmental obligations. This guidance requires that legal obligations associated with
the retirement of long-lived assets be recognized at fair value at the time the liability is incurred and capitalized as part of the related longlived asset. Over time, the liability is adjusted to its present value by recognizing accretion expense and the capitalized cost of the long-lived
asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. In the absence of quoted market prices, the
Association determines fair value by using present value techniques in which estimates of future cash flows associated with retirement activities
are discounted using a credit adjusted risk-free rate. Upon settlement of an asset retirement obligation, the Association will apply payment
against the estimated liability and incur a gain or loss if the actual retirement costs differ from the estimated recorded liability. Asset retirement
obligations are included in deferred credits and other liabilities.
Coal Mines: The Association has asset retirement obligations for the final reclamation costs and post-reclamation monitoring related to the
New Horizon Mine, the Fort Union Mine and the Colowyo Mine acquired December 1, 2011 in the acquisition of Colowyo Coal Company.
The acquisition resulted in the Association recording an additional $24.3 million of asset retirement obligations in 2011 related to the Colowyo
Mine (see Note 3—Acquisitions).
Fossil Steam Generation: The Association, including its undivided interest in jointly owned facilities, has asset retirement obligations related to
equipment, dams, ponds, ground water, wells and underground storage tanks at the fossil steam generating stations.
Transmission: The Association has an asset retirement obligation to remove a certain transmission line and related substation assets resulting
from an agreement to relocate the line. This work is scheduled to be completed in 2014.
Aggregate carrying amounts of asset retirement obligations are as follows (thousands):
2012
2011
Asset retirement obligation at beginning of year
Liabilities incurred
Liabilities settled
Accretion expense
Change in cash flow estimate
$30,777
10,960
—
2,751
—
$6,761
24,304
(740)
454
(2)
Asset retirement obligation at end of year
$44,488
$30,777
The Association also has asset retirement obligations with indeterminate settlement dates. These are made up primarily of obligations attached
to transmission and other easements that are considered by the Association to be operated in perpetuity and therefore the measurement of
the obligation is not possible. A liability will be recognized in the period in which sufficient information exists to estimate a range of potential
settlement dates as is needed to employ a present value technique to estimate fair value.
Memberships:
There are 44 $5 memberships outstanding at December 31, 2012 and 2011.
Patronage Capital:
Net margins of the Association are treated as advances of capital by the members and are allocated to the members on the basis of their electricity
purchases from the Association. Net losses are not allocated to members, but are offset by future margins.
24
2012 ANNUAL REPORT
Electric Sales Revenue:
Revenue from electric energy deliveries is recognized when delivered.
Other Operating Revenue:
Other operating revenue consists primarily of wheeling revenue and lease revenue. Wheeling revenue is received when the Association charges
other energy companies for transmitting electricity over the Association’s transmission lines. The lease revenue is primarily from certain power
sales arrangements that are required to be accounted for as operating leases since the arrangements are in substance leases because they convey
to others the right to use power generating equipment for a stated period of time. These leases are discussed further in Note 2—Leases.
Deferred Revenues:
The Association has recognized the benefit of certain deferred revenues assumed from Plains in connection with the merger in 2000. Prior
to the merger, 12 former Plains members made payments totaling $47.6 million to Plains for the prepayment of purchased power and 1 former
Plains member made an $11.8 million payment to Plains in order to buy out of its relationship with Plains. Plains recorded the amounts as
deferred revenues. The Association assumed the deferred revenues upon merging with Plains and included them in deferred credits and other
liabilities. Portions of these deferred revenues were recognized in income in various years which resulted in balances in the deferred revenue
accounts for the member prepayment and buyout payment of $4.8 and $0.8 million, respectively, at December 31, 2009. During 2010, the
$4.8 million member prepayment was recognized in member electric sales revenue and the $0.8 million buyout payment was recognized in
other operating revenue. Therefore, there are no balances remaining in the deferred revenue accounts for the member prepayment and buyout
payment at December 31, 2010 or subsequent years.
During 2007, the Association deferred the recognition of $20 million of non-member electric sales revenue earned during 2007 in accordance
with regulatory accounting requirements. $10 million of this deferred revenue was recognized in non-member electric sales revenue in each
of the years 2011 and 2012. Therefore, the balance of this deferred revenue, included in deferred credits and other liabilities, at December 31,
2012 and 2011 was $0 and $10 million, respectively.
with regulatory accounting requirements. The $10 million deferred revenue is included in deferred credits and other liabilities. This deferred
revenue will be recognized in non-member electric sales revenue in 2013.
with regulatory accounting requirements. The $55 million deferred revenue is included in deferred credits and other liabilities. This deferred
revenue will be recognized in non-member electric sales revenue prior to 2018.
The total of these deferred revenues is $65.0 million and $75.0 million at December 31, 2012 and 2011, respectively, and is included in deferred
credits and other liabilities. The accounting for deferred revenues is discussed further in Note 2—Accounting for Rate Regulation.
Income Taxes:
The Association is a non-exempt cooperative subject to federal and state taxation and, as a cooperative, is allowed a tax exclusion for margins
allocated as patronage capital. The liability method of accounting for income taxes is utilized, whereby changes in deferred tax assets or
liabilities result in the establishment of a regulatory asset or liability. A regulatory asset or liability associated with deferred income taxes
generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues.
Accounting for Rate Regulation:
The Association is subject to the accounting requirements related to regulated operations. In accordance with these accounting requirements,
some revenues and expenses have been deferred at the discretion of the Association’s Board of Directors, which has budgetary and rate-setting
authority, if it is probable that these amounts will be refunded or recovered through future rates. Regulatory assets are costs the Association
expects to recover from members based on rates approved by the Board of Directors in accordance with the Association’s rate policy. Regulatory
liabilities represent probable future reductions in rates associated with amounts that are expected to be refunded to members based on rates
approved by the Board of Directors in accordance with the Association’s rate policy. The Association recognizes regulatory assets and liabilities
as expenses or as a reduction in expenses concurrent with their recovery in rates. Regulatory assets are included in deferred charges. Regulatory
liabilities are included in deferred credits and other liabilities.
25
The Association was the lessee under five individual lease agreements of Craig Generating Station Unit 3 with a lease term through 2018.
Lease expense was recorded on a straight-line basis over the term of the lease based on total scheduled lease payments to be paid over the life
of the lease. Amounts paid in excess of or below recorded lease expense were recorded as prepaid lease expense. In 2002 through 2006, the
Association acquired the equity ownership interests in the five separate leases. The acquisitions of these equity interests were accounted for
under ownership accounting which would ordinarily have required that the balance of the prepaid lease be recognized as a current expense.
However, the current recognition of the prepaid lease expense was deferred under the accounting requirements related to regulated operations
and the amount of the deferral is accounted for as a regulatory asset. The regulatory asset for the deferred prepaid lease expense is being amortized into expense each year through the remaining original life of the lease ending in 2018. The amortization of the deferred prepaid lease
expense associated with the lease of Craig Generating Station Unit 3 was $6.5 million in 2012, 2011 and 2010 and is included in depreciation
and amortization. The deferred prepaid lease expense balance was $35.6 and $42.1 million at December 31, 2012 and 2011, respectively, and
is included in deferred charges.
On December 18, 2009, the Association acquired a 49 percent equity interest (including the 1 percent general partner equity interest) in the
Springerville Partnership which is the 100 percent owner of the Owner Lessor in the Springerville Generating Station Unit 3 Lease in which
the Association is the lessee. Upon acquisition, the Springerville Partnership and the Owner Lessor were consolidated by the Association in
accordance with the accounting guidance for business combinations and consolidations and pursuant to this guidance the acquisition was
accounted for as an acquisition of assets (see Note 3—Acquisitions and Note 9—Leases). The Association’s consolidation of the Springerville
Partnership and the Owner Lessor results in 100 percent of the Springerville Generating Station Unit 3 Lease expense being eliminated.
Therefore, there is no longer Springerville lease expense subsequent to the acquisition. Prior to the acquisition, lease expense was recorded on
a straight-line basis over the term of the lease based on total scheduled lease payments to be paid over the life of the lease. Amounts paid in
excess of or below recorded lease expense were recorded as prepaid lease expense. The Association had a pre-acquisition prepaid lease balance
of $106.7 million as of December 18, 2009 associated with the Springerville Generating Station Unit 3 Lease. Under the asset acquisition
approach used in the accounting for this transaction, the pre-acquisition prepaid lease balance would ordinarily have been expensed as a loss
on the acquisition of assets. However, the current recognition of the $106.7 million expense was deferred under the accounting requirements
related to regulated operations and the amount of the deferral is accounted for as a regulatory asset. The regulatory asset for the deferred
prepaid lease expense is being amortized into expense beginning December 18, 2009 through the remaining life of Springerville Generating
Station Unit 3 ending in 2056. The amortization of the deferred prepaid lease expense associated with the Springerville Generating Station
Unit 3 Lease was $2.3 million in 2012, 2011 and 2010 and is included in depreciation and amortization. The deferred prepaid lease expense
balance was $99.7 and $102.0 million at December 31, 2012 and 2011, respectively, and is included in deferred charges.
The regulatory asset related to deferred income tax expense is discussed further in Note 2—Income Taxes. The regulatory asset and regulatory
liability related to deferred derivative mark to market loss and gain are discussed further in Note 2—Derivatives. The regulatory liability related
to deferred revenues is discussed further in Note 2—Deferred Revenues.
Regulatory assets and liabilities are as follows (thousands):
Regulatory assets
Deferred income tax expense
Deferred derivative mark to market loss
Deferred prepaid lease expense—Craig 3 Lease
Deferred prepaid lease expense—Springerville 3 Lease
Regulatory liabilities
Deferred revenues
Net regulatory asset
26
2012
2011
$27,238
—
35,603
99,750
$28,061
772
42,076
102,040
162,591
172,949
65,000
75,000
65,000
75,000
$97,591
$97,949
2012 ANNUAL REPORT
Interchange Power:
The Association occasionally engages in interchanges, or non-cash swapping, of energy. Based on the assumption that all energy interchanged
will eventually be received or delivered in-kind, interchanged energy is generally valued at the average cost of fuel to generate power. Additionally,
portions of the energy interchanged are valued per contract with the utility involved in the interchange. When the Association is in a net
energy advance position, the advanced energy balance is recorded as an asset. If the Association owes energy, the net energy balance owed to
others is recorded as a liability. The net activity for the year is included in purchased power expense. The interchange asset of $606,000 at
December 31, 2012 is included in deposits and advances and the interchange liability of $730,000 at December 31, 2011 is included in accounts
payable. The net interchange activity recorded in purchased power expense was $(1.3) million, $853,000 and $(2.5) million in 2012, 2011 and
2010, respectively.
Evaluation of Subsequent Events:
The Association evaluated subsequent events through February 22, 2013 which represents when the consolidated financial statements were
available to be issued. As of this date, there were no subsequent events that require an adjustment to the consolidated financial statements or
that require disclosure in the consolidated financial statements. The Association has not evaluated subsequent events after the available to be
issued date.
New Accounting Pronouncements:
In May 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve
Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (“IFRS”).
This update provides a consistent definition of fair value and ensures that the fair value measurement and disclosure requirements are similar
between GAAP and International Financial Reporting Standards. This new guidance expands the disclosures on Level 3 inputs by requiring
quantitative disclosure of the unobservable inputs and assumptions, a description of the valuation processes and the sensitivity of the fair value
to changes in unobservable inputs. ASU 2011-04 was effective for the Association for the fiscal year beginning January 1, 2012. The adoption
of this update did not have a material impact on the Association’s financial position or results of operations.
In June 2011, the FASB issued ASU 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. This ASU requires
an entity to report the total of comprehensive income, including the components of net income and the components of comprehensive income,
in either a single continuous statement of comprehensive income or in two separate but consecutive statements. The ASU was effective for the
Association for the fiscal year beginning January 1, 2012. The adoption of this update did not have a material impact on the Association’s
financial position or results of operations.
In September 2011, the FASB issued ASU 2011-09, Compensation-Retirement Benefits-Multiemployer Plans (Subtopic 715-80): Disclosures
about an Employer’s Participation in a Multiemployer Plan. The amendment requires an employer that participates in multiemployer pension
plans to provide additional quantitative and qualitative disclosures in order to provide more detailed information about the employer’s involvement in multiemployer pension plans. In addition, this amendment also includes changes in the disclosures required for multiemployer plans
that provide postretirement benefits other than pensions. ASU 2011-09 is effective for the Association for the fiscal year beginning January 1,
2012. The adoption of this update did not have a material impact on the Association’s financial position or results of operations.
In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This amendment requires companies to disclose information about financial instruments that have been offset and related arrangements to enable users
of its financial statements to understand the affect of those arrangements on its financial condition. The amendment requires both net (offset
amounts) and gross information to be provided in the notes to the financial statements for relevant assets and liabilities that are offset. In
January 2013, the FASB issued ASU 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.
This amendment limits the scope of the new balance sheet offsetting disclosure requirements to derivatives (including bifurcated embedded
derivatives), repurchase agreements and reverse repurchase agreements and securities borrowing and lending transactions. ASU 2013-01 is
effective for the Association for the fiscal year beginning January 1, 2013. The adoption of these updates is not expected to have a material
impact on the Association’s financial position or results of operations.
Reclassifications:
Certain reclassifications have been made to the prior year financial statements to conform to the 2012 presentations.
27
Note 3—Acquisitions
Thermo Cogeneration Partnership, LP (“TCP”), owner of J.M. Shafer Generating Station, and Greenhouse Holdings, LLC (“GHH”)
On December 2, 2011, the Association acquired the 100 percent equity interests (including the general and the limited partner equity interests)
in TCP and GHH. TCP owns the J.M. Shafer Generating Station (formerly known as the Fort Lupton Generating Station), a 272-megawatt
natural gas-fired combined cycle power plant located near Fort Lupton, Colorado. TCP is contractually obligated to sell 150 megawatts of the
272-megawatt net generating capability of the J.M. Shafer Generating Station according to the terms of a purchase power agreement with the
Association (the “Tri-State PPA”) from July 1, 2009 through June 30, 2019 (see Note 7—Leases). TCP is also contractually obligated to sell the
remaining 122 megawatts of the net generating capability of J.M. Shafer Generating Station to a third party under a separate purchase power
agreement (the “PPA”) through June 30, 2019. At the time of the acquisition, GHH was the owner of a greenhouse facility (“Greenhouse 1”)
and land adjacent to the J.M. Shafer Generating Station and leased this greenhouse to a third-party operator. GHH obtained water supply,
thermal energy and wastewater discharge services from TCP pursuant to an ancillary services agreement and sold these services to the
Greenhouse 1 operator and to an adjacent greenhouse that the operator owns. The December 2, 2011 acquisition will effectively allow the
Association to expand its portfolio of generation resources in order to serve the increasing electric power requirements of its members.
The accounting standard for business combinations requires all identifiable assets and assumed liabilities to be measured and recognized
separately from goodwill. This includes measuring and recognizing identifiable intangible assets, or liabilities, if it arises from contractual or
other legal rights (contractual-legal criterion), or is capable of both being separated from the entity and sold, transferred, licensed, rented or
exchanged either on its own or combined with a related contract, identifiable asset or liability (separability criterion). The PPA met these recognition criteria. Therefore, an intangible asset with a fair value of $55.5 million was recognized for the amount that the PPA contract terms
were above market value at the acquisition date. This finite-lived intangible asset is included in other assets and investments on the consolidated
statements of financial position and will be amortized on a straight-line basis over the remaining life of the PPA through June 30, 2019 (see
Note 4—Goodwill and Intangibles).
The Tri-State PPA contract terms were also above market value at the acquisition date by an estimated amount of $6.4 million. This contract
was a pre-existing contractual relationship between the Association and TCP. According to the accounting standard for business combinations,
this pre-existing relationship is considered effectively settled upon acquisition since the relationship between the Association and TCP becomes
an intercompany relationship as of the acquisition date. Therefore, a gain or loss is required to be recognized separate from the business combination for the lesser of the amount by which the contract is favorable or unfavorable compared to current market terms, or the amount of the
stated contract’s settlement provisions. Since the Tri-State PPA is not cancelable and does not contain settlement terms, a loss of $6.4 million
was recognized at the acquisition date separate from the business combination accounting. This 2011 loss is included in other income on the
Association’s consolidated statements of operations.
The Association paid a total of $210.7 million (net of cash acquired) for all aspects of this transaction. $204.3 million was consideration trans
ferred by the Association in the business combination and $6.4 million was paid to settle the pre-existing Tri-State PPA contractual relationship.
The Association followed the acquisition method of accounting in accordance with the accounting standard related to business combinations
(see Note 2—Business Combinations). Additionally, since this acquisition included the acquisition of an electric generating station, J.M. Shafer
Generating Station, the accounting prescribed by the RUS for the acquisition of electric plant was also followed. This required that the electric
plant be recorded at its estimated original cost and that the estimated accumulated depreciation from its original placed in service date until
the acquisition date be recorded. The difference between the resulting net book value of the plant and the fair value of the plant is recorded as
an acquisition adjustment, which is included in electric plant in service on the statements of financial position.
The fair values of the assets acquired and liabilities assumed in the acquisition on December 2, 2011, as accounted for under the accounting
prescribed by the RUS, are summarized in the following table (thousands):
Current assets (excluding cash acquired) less current liabilities
Original cost of electric plant in service
Accumulated depreciation at time of acquisition
Acquisition adjustment
Materials and supplies inventory
Greenhouse
Land
Intangible asset—PPA premium
Goodwill (Misc. Deferred Debit)
$661
231,000
(126,364)
(32,344)
2,278
761
790
55,541
71,937
Total net assets acquired
$204,260
28
2012 ANNUAL REPORT
Goodwill represents the cost of the consideration transferred in excess of the fair value of assets acquired less liabilities assumed. The goodwill
of $71.9 million that was recognized was attributable to a premium paid by the Association for the right to control the acquired entities as
well as synergies expected to be gained from the integration of the J.M. Shafer Generating Station into the Association’s portfolio of generation resources. The accounting prescribed by the RUS does not include the goodwill concept and therefore the goodwill is also described
as a Miscellaneous Deferred Debit to reflect the RUS accounting. The accounting for the goodwill is discussed in Note 4—Goodwill
and Intangibles.
Acquisition costs were expensed as incurred resulting in recognizing $1.4 million of expense and are included in other deductions.
Subsequent to the acquisition, the Association terminated the current greenhouse lease agreement between GHH and the third party greenhouse operator. The Association also began the process of removing Greenhouse 1 since this asset provided no future economic benefit to the
Association. As of December 31, 2011, Greenhouse 1 was considered to be fully impaired and worthless. Therefore, the $761,000 asset value
recognized at the acquisition date was expensed in 2011 and is included in other deductions.
Subsequent to the December 2, 2011 acquisition, the results of operations from TCP have been included in the Association’s consolidated
statements of operations. TCP contributed revenue, primarily from the PPA, of $12.5 and $1.0 million for 2012 and 2011, respectively, which
is included in other operating revenue. TCP also contributed expenses of $16.1 million and $651,000 for 2012 and 2011, respectively, which
are included in operating expenses. Additionally, the $761,000 write off of the Greenhouse in 2011 is included in other deductions.
Colowyo Coal Company LP (“Colowyo Coal”)
On December 1, 2011, the Association’s 99 percent owned subsidiary, Western Fuels-Colorado, acquired Colowyo Coal by acquiring 100 percent of the equity interests in its owners (Kennecott Colorado Coal Company (“KCCC”) and Rio Tinto White Horse Company (“RTWHC”)).
KCCC (subsequently renamed Axial Basin Coal Company) is the general partner of Colowyo Coal. RTWHC (subsequently renamed Taylor
Creek Holding Company) is the limited partner of Colowyo Coal. Colowyo Coal owns a large surface coal mine in Moffat County, Colorado
and sells the coal it produces through two coal sales agreements to the Craig Generating Station which is operated by the Association. One
coal sales agreement obligates Colowyo Coal to sell coal through 2017 to the Association through Western Fuels-Colorado as agent for the
Association for its use at the Craig Generating Station. The other coal sales agreement obligates Colowyo Coal to sell coal to the other Craig
Generating Station owner participants (the “Yampa Participants”) though 2017. This acquisition will effectively ensure a reliable and affordable
supply of coal to the Craig Generating Station for the expected life of the power plant.
The accounting standard for business combinations requires all identifiable assets and assumed liabilities to be measured and recognized separately from goodwill. This includes measuring and recognizing identifiable intangible assets, or liabilities, if it arises from contractual or other
legal rights (contractual-legal criterion), or is capable of both being separated from the entity and sold, transferred, licensed, rented or exchanged
either on its own or combined with a related contract, identifiable asset or liability (separability criterion). The coal sales contract with the
Yampa Participants met these recognition criteria. Therefore, an intangible liability with a fair value of $18.0 million was recognized in the
December 1, 2011 acquisition for the amount that the contract terms were below market at the acquisition date. This finite-lived intangible
liability is included in deferred credits and other liabilities on the consolidated statements of financial position and will be amortized based
upon the contracted tonnage with the Yampa Participants over the remaining life of the coal contract through December 31, 2017 (see Note
4—Goodwill and Intangibles).
The coal sales agreement with the Association also had terms that were below market value at the acquisition date by an estimated amount
of $31.1 million. This contract was a pre-existing contractual relationship between the Association and Colowyo Coal. According to the
accounting standard for business combinations, this pre-existing relationship is considered effectively settled upon acquisition since the
relationship between the Association and Colowyo Coal becomes an intercompany relationship as of the acquisition date. Therefore, a gain
or loss is required to be recognized separate from the business combination for the lesser of the amount by which the contract is unfavorable
or favorable compared to current market terms, or the amount of the stated contract’s settlement provisions. Since the coal sales contract with
the Association is not cancelable and does not contain settlement terms, a gain of $31.1 million was recognized separate from the business
combination accounting. This 2011 gain is included in other income on the Association’s consolidated statements of operations.
The Colowyo Bonds assumed in the acquisition are required to be recorded at their acquisition date fair value. It was determined that the
fair value of the Colowyo Bonds was $41.9 million, which was $7.4 million greater than the $34.5 million outstanding debt balance. Addi
tionally, the Association assumed debt associated with the financing of mine equipment used at the mine. This debt was recorded at its $7.7
million outstanding debt balance which was estimated to be approximately equal to fair value. The acquisition debt is shown in Note 6—
Long-Term Debt.
The accounting for the business combination includes the accounting for deferred income taxes related to the acquisition. See Note 8—
Income Taxes for further discussion of the accounting for income taxes by the Association.
29
The Association, through Western Fuels-Colorado, paid cash in the net amount of $77.0 million for all aspects of this transaction. $108.1
million was considered to have been transferred by the Association in the business combination (net of cash acquired). This was offset by the
receipt of $31.1 million that was considered to have been paid by Colowyo Coal to the Association to settle the pre-existing unfavorable coal
sales agreement. Other consideration in the business combination includes liabilities assumed.
The Association followed the acquisition method of accounting in accordance with the accounting standard related to business combinations
(see Note 2—Business Combinations). The fair values of the assets acquired and liabilities assumed in the acquisition on December 1, 2011,
including the accounting for deferred income taxes and certain other tax matters, are summarized in the following table (thousands):
Assets
Current assets (excluding cash acquired) less current liabilities
Building and land improvements
Non-mineral land
Fee land outside of permitted mine plan
Personal property
Mineral rights
Deferred tax assets
Deferred tax regulatory asset
Goodwill (Misc. Deferred Debit)
$15,696
8,230
4,520
10,071
61,730
54,980
18,706
10,881
28,353
Total assets acquired
$213,167
Liabilities
Colowyo Bonds
Premium on Colowyo Bonds
Mine equipment loans
Colowyo Bonds and mine equipment loans accrued interest
Asset retirement obligation
Intangible liability—coal contracts below market terms with Yampa
Participants
Deferred tax liabilities
$34,475
7,455
7,956
478
24,304
17,950
12,480
Total liabilities assumed
$105,098
Cash consideration transferred (net of cash acquired)
$108,069
Goodwill represents the cost of the total consideration transferred in excess of the fair value of assets acquired less liabilities assumed. The
goodwill of $28.4 million that was recognized was attributable to a premium paid by Western Fuels-Colorado for the right to control the
acquired entities in order to ensure a reliable and affordable supply of coal for the Craig Generating Station for the expected life of the power
plant and also to having an established workforce in place. The accounting prescribed by the RUS does not include the goodwill concept and
therefore the goodwill is also described as a Miscellaneous Deferred Debit to reflect the RUS accounting. The accounting for the goodwill
is discussed in Note 4—Goodwill and Intangibles.
Acquisition costs were expensed as incurred resulting in recognizing $2.2 million in expense and are included in other deductions.
Subsequent to the December 1, 2011 acquisition, the results of operations from Colowyo Coal have been included in the Association’s
consolidated statements of operations. Approximately 68 percent of the total mine expenses relate to providing coal to the Association for use
at the Craig Generating Station. The incremental increase in these expenses over the expense of the Association purchasing the coal from
Colowyo Coal prior to the acquisition is $22.2 and $1.0 million for 2012 and 2011, respectively, and these are included in fuel expense. The
remaining mine operation efforts relate to selling coal to the Yampa Participants for their use at the Craig Generating Station and the net
losses of $5.9 million and $120,000 for 2012 and 2011, respectively, are included in other income.
30
2012 ANNUAL REPORT
Springerville Unit 3 Partnership LP
On December 18, 2009, the Association acquired a 49 percent equity interest (including the 1 percent general partner equity interest) in the
Springerville Unit 3 Partnership LP (the “Springerville Partnership”) which is the 100 percent owner of the Owner Lessor in the Springerville
Generating Station Unit 3 Lease in which the Association is the lessee. The Association has the full, exclusive and complete right, power
and discretion to operate, manage and control the affairs of the Springerville Partnership. Therefore, beginning on December 18, 2009, the
Springerville Partnership and the Owner Lessor were consolidated by the Association in accordance with the accounting guidance for business
combinations and consolidations and pursuant to this guidance the acquisition was accounted for as an acquisition of assets.
The Association’s consolidation of the Springerville Partnership and the Owner Lessor results in 100 percent of the Springerville Generating
Station Unit 3 Lease expense being eliminated. Therefore, there is no longer Springerville lease expense subsequent to the acquisition. Instead,
100 percent of the assets, liabilities and expenses of the Springerville Partnership and the Owner Lessor (consisting solely of the Springerville
Generating Station Unit 3 assets, debt and related expenses) are included in the consolidated financial statements of the Association (see Note
6—Long-Term Debt and Note 9—Leases).
On December 22, 2010, the Association increased its equity interest in the Springerville Partnership to 51 percent by acquiring an additional
2 percent equity interest in the Springerville Partnership. The Association paid cash of $5,148,000 for the 2 percent equity interest of
$4,902,000 as of this date. The acquisition was accounted for as an equity transaction. Therefore, the $5,148,000 acquisition resulted in the
noncontrolling interest being reduced by $4,902,000 and the $246,000 cash paid in excess of the equity interest being recorded as a reduction
in patronage capital equity attributable to the acquisition of the noncontrolling interest. The loss attributable to the noncontrolling equity
interest was $3.0 million, $3.8 million and $4.7 million for 2012, 2011 and 2010, respectively.
Note 4—Goodwill and Intangibles
Goodwill and Intangible Assets:
During 2011, the Association recognized goodwill in the amount of $71.9 million related to the acquisition of TCP and GHH and $28.4
million related to the acquisition of Colowyo Coal (see Note 3—Acquisitions). Goodwill represents an asset recognized in a business combination that is initially measured as the excess of the fair value of the acquired business over the fair value of the net identifiable assets acquired.
Goodwill is generally treated under GAAP as an indefinite lived asset that is not subject to amortization and is instead required to be evaluated
annually for impairment. However, during 2012, the Association adopted a regulatory accounting approach for recovering the goodwill costs
pursuant to the accounting requirements related to regulated operations (see Note 2—Accounting for Regulation). Under this approach
(effective January 1, 2012), the goodwill amounts are being amortized over specific time periods for recovery in rates. The goodwill of $71.9
million related to the acquisition of TCP and GHH is being amortized over the 25 year remaining life of the J.M. Shafer Generating Station.
This results in amortization expense of $2.8 million per year that is included in depreciation and amortization expense. The goodwill of
$28.4 million related to the acquisition of Colowyo Coal is being amortized over the 44 year remaining life of the Craig Generating Station
since the coal mine was acquired primarily for its use. This results in amortization expense of $644,000 per year that is included in depreciation
and amortization expense. The goodwill amortization will be recognized over each of the next five years and thereafter as follows (thousands):
2013
2014
2015
2016
2017
Thereafter
$ 3,493
3,493
3,493
3,493
3,493
79,331
$96,796
During 2011, the Association recognized an intangible asset in the amount of $55.5 million related to its acquisition of TCP and GHH (see
Note 3—Acquisitions). This finite-lived asset represents the amount that the PPA contract terms were above market value at the December 2,
2011 acquisition date. An intangible asset with a finite life is subject to amortization over its remaining economic useful life on a straight-line
basis unless there is a method other than straight-line that is reliably determined and best reflects how that asset or liability is consumed. The
$55.5 million PPA intangible asset is being amortized on a straight-line basis over the remaining life of the PPA through June 30, 2019. The
straight-line method is consistent with the terms of the PPA as this contract is for a fixed amount of capacity at a fixed capacity rate that stays
constant over the term of the contract.
31
The amortization of the PPA intangible asset is accounted for as a reduction of the revenue generated by the PPA and is included in other
operating revenue. The amortization was $7.3 million and $610,000 in 2012 and 2011, respectively. Amortization will be recognized over each
of the next five years and thereafter as follows (thousands):
2013
2014
2015
2016
2017
Thereafter
$ 7,324
7,324
7,324
7,324
7,324
10,987
$47,607
The carrying amounts of goodwill and intangible assets are presented in the consolidated statements of financial position. The accounting
prescribed by the RUS does not include the goodwill concept and therefore the goodwill is also described as a Miscellaneous Deferred Debit
to reflect the RUS accounting.
The carrying amounts are comprised of the following (thousands):
2012
2011
Goodwill (Misc Deferred Debit)—TCP
Goodwill (Misc Deferred Debit)—Colowyo Coal
Intangible asset—TCP PPA premium
$69,087
27,709
47,607
$71,937
28,353
54,931
Total
$144,403
$155,221
Intangible Liabilities:
During 2011, Western Fuels-Colorado recognized an intangible liability in the amount of $18.0 million related to its acquisition of Colowyo
Coal (see Note 3—Acquisitions). This finite-lived liability relates to the amount that the coal contract with the Yampa Participants was below
market value at the December 1, 2011 acquisition date. The intangible liability recognized in the Colowyo Coal acquisition is being amortized
based upon the contracted tonnage with the Yampa Participants over the remaining life of the coal contract ending in 2017. The intangible
liability balance of $15.1 and $17.7 million as of December 31, 2012 and 2011, respectively, is included in other deferred credits.
The amortization of the Colowyo Coal intangible liability is accounted for as an increase in other income. The amortization benefit of
$2.6 million and $211,000 was recognized in 2012 and 2011, respectively, and is estimated to be recognized over each of the next five years
as follows (thousands):
2013
2014
2015
2016
2017
$ 2,620
3,125
3,125
3,125
3,124
$15,119
32
2012 ANNUAL REPORT
Note 5—Electric Plant
The Association’s investment in electric plant and the related annual rates of depreciation or amortization calculated using the straight-line
method are as follows (thousands):
Annual Depreciation Rate
2012
2011
.44% to 3.10%
2.0% to 2.88%
3.0% to 30.00%
2.8% to 5.60%
$3,235,179
1,035,369
344,761
241,263
$3,188,111
922,371
312,953
228,049
Generation plant
Transmission plant
General plant
Other
Electric plant in service (at cost)
Less allowances for depreciation and amortization
Electric plant
4,856,572
152,355
(1,929,872)
$3,079,055
4,651,484
183,178
(1,831,985)
$3,002,677
Effective January 1, 2011, the Association adopted depreciation rates that reflect rates determined in depreciation rate studies performed
and completed during 2011 for most of the Association’s generating stations. These new rates resulted in a reduction in 2011 depreciation of
$32.8 million.
At December 31, 2012, the Association had $57.2 million of commitments to complete construction projects of which approximately $46.8,
$7.9 and $2.5 million are expected to be incurred in 2013, 2014 and 2015, respectively.
The Purchase Option and Development Agreement was executed on July 26, 2007 between the Association and Sunflower Electric Power
Corporation (“Sunflower”) and other Sunflower parties. The agreement calls for the Association to make option payments totaling $55 million
to Sunflower and/or the other Sunflower parties in exchange for the development rights to develop a new coal-fired generating unit or units at
Sunflower’s existing single-unit Holcomb Station in western Kansas. Upon execution, $25 million was paid. In 2008, $5 million was paid and
the remainder will be paid on the purchase date. The purchase date will be designated by the Association, Sunflower and the other parties to
the Purchase Option and Development Agreement after the Association exercises its option to acquire the development rights. The purchase
date cannot currently be estimated due to legal uncertainties surrounding the status of the necessary air permits. The original air permit application was denied by the Kansas Department of Health and Environment (“KDHE”) in October 2007 and the Association and Sunflower
appealed the denial to the Kansas courts. Subsequent to the denial of the air permit, Sunflower entered into an agreement with the governor
of Kansas that could result in the KDHE issuing a permit for one new coal-fired generating unit at Holcomb Station of 895 megawatts. As a
result of the agreement, Sunflower and the Association withdrew their appeal of the denial of the original air permit application. The KDHE
issued the new permit on December 16, 2010. The Sierra Club filed an appeal of the new permit with the Kansas Court of Appeals on January
14, 2011 and the case was immediately transferred to the Kansas Supreme Court. Sunflower and the Association intervened in the appeal and
the Court’s decision is pending. Excluding the cost of land and water rights, the cost of developing the units incurred by the Association as of
December 31, 2012 is $71.9 million. The Association is unable to project the ultimate outcome of this matter, but it intends to pursue the
revised air permit process to conclusion. The Association is unable to project when the air permit application process may conclude.
33
Note 6—Long-Term Debt
The mortgage notes payable and pollution control revenue bonds are secured on a parity basis by a Master First Mortgage Indenture, Deed
of Trust and Security Agreement. Substantially all the assets, rents, revenues and margins of the Association are pledged as collateral. The
Springerville certificates are secured by the assets of Springerville Generating Station Unit 3 (see Note 9—Leases). The Colowyo Bonds are
secured by the coal sales contract with the Association and the coal sales contract with the Yampa Participants (see Note 3—Acquisitions).
All long-term debt contains certain restrictive financial covenants and consists of the following (thousands):
Mortgage notes payable
2% RUS, due through 2017
5% RUS, due through 2026
1.95% to 10.81% FFB, 4.75% average for 2012,
due through 2044
4.50% to 9.05% CFC, 6.16% average for 2012,
due through 2022
4.38% to 7.24% CoBank, ACB, 6.12% average for 2012,
due through 2042
First Mortgage Bonds, Series 2010A, 6.00% due 2040
First Mortgage Obligation, Series 2009C, Tranche 1,
6.00%, due 2019
First Mortgage Obligation, Series 2009C, Tranche 2,
6.31%, due 2021
Variable rate CFC, as determined by CFC, 3.13%
average for 2012, due through 2026
Variable rate Grantor Trust Obligations, as determined
by CFC, 0.51% average for 2012, due 2017
Variable rate, 2011 Credit Agreement, LIBOR based
revolving credit, 1.76% average for 2012, due 2016
Pollution control revenue bonds
Platte County, WY Daily Adjustable Rate Series 1984,
0.21% average for 2012, due 2014
City of Gallup, NM, 5.00%, Series 2005,
due through 2017
Moffat County, CO Variable Rate Demand Series 2009,
0.21% average for 2012, due 2036
Springerville certificates
Series A, 6.04%, due 2018
Series B, 7.14%, due 2033
Colowyo Coal
Colowyo Bonds, 10.19%, due 2016
Mine Equipment Loans, 7.75%, due 2014
Other
Less advance payments to RUS
Total debt
Less current maturities
Long-term debt
2012
2011
$215
6,472
$268
8,739
1,283,032
1,196,218
135,232
154,486
167,807
499,325
74,359
499,327
190,000
190,000
110,000
110,000
766
802
21,025
24,440
65,000
205,000
48,000
48,000
25,988
30,646
46,800
46,800
193,300
423,630
224,293
424,627
34,044
4,920
850
(267,985)
41,721
7,731
850
(391,100)
2,988,421
(198,053)
2,897,207
(185,055)
$2,790,368
34
$2,712,152
2012 ANNUAL REPORT
The Platte County bonds may be “put” back for remarketing at any time and may be converted to a long-term fixed rate at the option of the
Association. A $49.1 million letter of credit with National Rural Utilities Cooperative Finance Corporation (“CFC”) secures payment of
these bonds and as of December 31, 2012 had an expiration date of July 28, 2014.
In February 2009, the Association refunded the Moffat County, CO Weekly Adjustable Rate Series 1984 Bonds and issued the $46.8 million
Moffat County, CO, Variable Rate Demand Pollution Control Revenue Refunding Bonds, Series 2009 (“Series 2009 Bonds”) with a 364 day,
direct pay letter of credit provided by Bank of America, N.A. In December 2012, the letter of credit from Bank of America, N.A. was extended
for an additional 364 days to mature in January 2014.
The Association has a 51 percent equity interest (including the 1 percent general partner equity interest) in the Springerville Partnership
through the acquisitions of the equity interests in 2009 and 2010 (See Note 3—Acquisitions). Subsequent to the 2009 acquisition, the
consolidated financial statements of the Association include its interest in the Springerville Partnership which is the 100 percent owner of
the Owner Lessor in the Springerville Generating Station Unit 3 Lease (see Note 9—Leases) in which the Association is the lessee. Therefore,
100 percent of the assets, liabilities and expenses of the Springerville Partnership and the Owner Lessor (consisting solely of the Springerville
Generating Station Unit 3 assets, debt and related expenses) are included in the consolidated financial statements of the Association. This
includes 100 percent of the Tri-State Generation and Transmission Association, Inc. 2003 Series A and Series B Pass Through Trust
Certificates which, along with owner equity, provided funding for the construction of the Springerville Generating Station Unit 3.
At December 31, 2012, the Association had two unused committed lines of credit totaling $75 million with scheduled expirations for $25
million in 2014 and $50 million in 2015. On January 4, 2013, the $50 million line of credit was extended to 2016. Both lines of credit are
expected to be renewed or extended prior to expiration.
In July 2011, the Association entered into an agreement (the “2011 Credit Agreement”) with Bank of America, N.A. (“Bank of America”) as
Administrative Agent and CoBank, ACB (“CoBank”) and Bank of America as Joint Lead Arrangers for a secured revolving credit facility
with a total commitment of $500 million for a term of 5 years that expires in July 2016.
On December 1, 2011, the Association’s subsidiary, Western Fuels-Colorado, purchased Colowyo Coal (see Note 3—Acquisitions). As a result
of the acquisition, the Coal Contract Receivable Collateralized Bonds (“Colowyo Bonds”) with an interest rate of 10.19 percent and totaling
$41.9 million, in the par amount of $34.5 million plus a premium of $7.4 million to reflect the fair market value as of December 1, 2011, were
added to the Association’s long-term debt. The debt was recorded at the acquisition date fair value per the accounting standard for business
combinations. On December 20, 2011, Colowyo Coal entered into an in-substance defeasance for the $34.5 million principal outstanding and
for the $10.3 million of total future interest payments on the Colowyo Bonds by purchasing U.S. Treasury Notes with a principal amount of
$42.0 million for a price of $44.8 million. The in-substance defeasance does not relieve Colowyo Coal and the Association of liability for the
Colowyo Bonds and therefore the debt continues to be shown as debt on the statements of financial position. The defeasance investments,
U.S. Treasury Notes totaling $33.5 million as of December 31, 2012, are shown as investment in securities pledged as collateral on the statements of financial position.
RUS allows borrowers to make advance payments that will be used to pay future debt. These advances are irrevocable and can only be used to
pay RUS or Federal Financing Bank (“FFB”) debt. The advance payments earn interest at a 5 percent rate. The amounts advanced to RUS are
$268 and $391 million as of December 31, 2012 and 2011, respectively.
At December 31, 2012, the Association had FFB commitments to advance additional construction funds of $462 million.
Annual maturities of total debt at December 31, 2012 are as follows (thousands):
2013
2014
2015
2016
2017
Thereafter
$ 198,053
227,158
180,235
155,575
177,215
2,050,185
$2,988,421
35
Note 7—Fair Values of Financial Instruments
The fair values of long-term debt were estimated using discounted cash flow analyses based on the Association’s current incremental borrowing
rates for similar types of borrowing arrangements. These valuation assumptions utilize observable inputs based on market data obtained from
independent sources and are therefore considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market corroborated
inputs). Fair values of marketable securities are presented in Note 2—Marketable Securities and the fair values of derivative instruments are
presented in Note 2—Derivatives. The carrying amounts and fair values of the Association’s long-term debt are as follows (thousands):
2011
2012
RUS
FFB
CFC
First Mortgage Bonds,
Series 2010A
First Mortgage Obligations,
Series 2009C
Pollution control revenue bonds
2011 Credit Agreement
Grantor Trust Obligations
CoBank, ACB
Springerville certificates
Colowyo Bonds
Mine Equipment Loans
Other
Less: Advance payments to RUS
Carrying
Amount
Estimated
Fair Value
Carrying
Amount
Estimated
Fair Value
$6,687
1,283,032
135,998
$7,656
1,500,764
149,330
$9,007
1,196,218
155,288
$10,011
1,472,435
177,012
499,325
667,360
499,327
657,835
300,000
120,788
65,000
21,025
167,807
616,930
34,044
4,920
850
337,740
121,550
63,316
20,533
175,680
738,015
34,893
5,100
761
300,000
125,446
205,000
24,440
74,359
648,920
41,721
7,731
850
339,508
125,784
215,965
24,844
85,237
747,646
41,721
7,731
736
3,256,406
(267,985)
3,822,698
(267,985)
3,288,307
(391,100)
3,906,465
(391,100)
$2,988,421
$3,554,713
$2,897,207
$3,515,365
Note 8—Income Taxes
Under the liability method, deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets
and liabilities for financial reporting purposes and for income tax purposes. Components of the Association’s net deferred tax liability are as
follows (thousands):
Deferred tax assets
Safe harbor lease receivables
Net operating loss carryforwards
Alternative minimum tax credit carryforwards
Deferred debt charges
Deferred revenues
Colowyo Coal—coal contract intangible liability
Other
Deferred tax liabilities
Asset basis differences including safe harbor assets
Depreciation
Capital credits from other associations
Net deferred tax liability
36
2012
2011
$42,005
39,008
3,834
2,129
24,460
5,691
43,519
$43,591
18,961
3,834
3,000
28,223
6,675
38,720
160,646
143,004
114,130
26,468
30,179
103,979
22,166
27,813
170,777
153,958
$(10,131)
$(10,954)
2012 ANNUAL REPORT
The $823,000 decrease in the net deferred tax liability from $10.9 million at December 31, 2011 to $10.1 million at December 31, 2012 is
not recognized as a tax benefit in 2012 due to the Association’s regulatory accounting treatment of deferred taxes. Instead, the tax benefit
is deferred and reflected as a decrease in the regulatory asset established for deferred income tax expense. The regulatory asset account for
deferred income tax expense has a balance of $27.2 million and $28.1 million at December 31, 2012 and 2011, respectively. The regulatory
asset balance includes $17.1 million related to the 2011 acquisition of Colowyo Coal (see Note 3—Acquisitions). The accounting for regulatory
assets is discussed further in Note 2—Accounting for Rate Regulation.
The Association had a $50.4 million taxable loss for 2012. At December 31, 2012, the Association has a net operating loss carryforward of
$103.7 million which, if not utilized, will expire between 2030 and 2032. The future reversal of existing temporary differences will morelikely-than-not enable the realization of the net operating loss carryforward.
The Association had an income tax benefit of $0, $10,000 and $9.7 million for 2012, 2011 and 2010 respectively. The Association has $3.8
million of alternative minimum tax credit carryforwards at December 31, 2012 to offset future regular taxes payable.
Note 9—Leases
Springerville Generating Station Unit 3 Lease:
In October 2003, the Association entered into a series of agreements to develop a 418-megawatt, coal-fired generating facility near
Springerville, Arizona, called Springerville Generating Station Unit 3 and for the Association to act as the construction agent for the benefit
of Springerville Unit 3 Holding LLC (the “Owner Lessor”). The agreements also called for the Association to be the lessee of the unit
under the Springerville Generating Station Unit 3 Lease. On July 28, 2006, the construction of the facility was completed and this operating
lease commenced. The Association is committed to make semiannual lease payments to the Owner Lessor for a 34-year lease term extending
through July 2040. The semiannual lease payments are comprised of amounts equal to the long-term and short-term bond commitments as
well as the repayment of equity funds to the Owner Lessor. In turn, the Owner Lessor is obligated to pay principal and interest on the bonds
with the lease payment proceeds received from the Association.
On December 18, 2009, the Association acquired a 49 percent equity interest (including the 1% general partner equity interest) in the
Springerville Partnership which is the 100 percent owner of the Owner Lessor. On December 22, 2010, the Association increased its equity
interest in the Springerville Partnership to 51 percent by acquiring an additional 2 percent equity interest in the Springerville Partnership. Upon
the December 18, 2009 acquisition, the Springerville Partnership and the Owner Lessor were consolidated by the Association in accordance
with the accounting guidance for business combinations and consolidations and pursuant to this guidance the acquisition was accounted for
as an acquisition of assets (see Note 3—Acquisitions). The Association’s consolidation of the Springerville Partnership and the Owner Lessor
results in 100 percent of the Springerville Generating Station Unit 3 Lease expense being eliminated. Therefore, there is no longer lease expense
subsequent to the acquisition. Instead, 100 percent of the assets, liabilities and expenses of the Springerville Partnership and the Owner Lessor
(consisting solely of the Springerville Generating Station Unit 3 assets, debt and related expenses) are included in the consolidated financial
statements of the Association.
Upon reaching a 51 percent equity ownership interest in the Springerville Partnership at December 22, 2010, the Association’s commitments
for Springerville Generating Station Unit 3 Lease payments reflect the amount of the payments less the debt commitments for the Springerville
certificates reflected in Note 6—Long-Term Debt and the amount of the payments that come back to the Association as the 51 percent equity
owner of the Springerville Partnership. The lease payment commitments relating to repayment of 49 percent of the equity funds at December
31, 2012 are as follows (thousands):
2013
2014
2015
2016
2017
Thereafter
$54
55
56
59
—
188,883
$189,107
In the 29th year of the lease and at the end of the 34-year lease term, the Association will have an option to acquire any remaining portion not
previously purchased of the leased facility for a fair market value price determined in October 2003 as of each of those dates. Alternatively, at
the end of the 34-year lease term, the Association will have an option to renew the lease for a term of up to 42 months and a second option to
extend the lease for an additional term of up to 54 months.
37
In accordance with the Facility Lease Agreement and other related agreements, the Association has provided guarantees to the Owner Lessor
for certain events that extend through the term of the lease. These include customary general and tax indemnities as well as protection for the
Owner Lessor against changes in regulatory law that would have a detrimental impact on the lease assumptions. Subsequent to the acquisitions
of 51 percent of the equity interests in 2009 and 2010, the Association only has guarantees to others with respect to the 49 percent equity
interest owner. The Association believes that the likelihood of these guarantee events occurring is remote and therefore no liability is recorded
as of December 31, 2012 and 2011.
Generating Stations with Gas Tolling Arrangements:
The Association has entered into power purchase arrangements that are required to be accounted for as operating leases since the arrangements
are in substance leases because they convey to the Association the right to use power generating equipment for a stated period of time. One
such agreement began in June 2008 and ended May 2012 for the use of the Rawhide Generating Station (owned by Platte River Power
Authority). This agreement allowed the Association to toll natural gas for 100 megawatts of power from the combustion turbines beginning
in 2008 with a decline to 50 megawatts in 2012. The Association also has a 10-year agreement with Brush Cogeneration Partners to toll
natural gas at the Brush Generating Station for 72 megawatts which began on October 1, 2009. Additionally, the Association has a 10-year
agreement with Thermo Cogeneration Partnership to toll natural gas at the J.M. Shafer Generating Station (formerly the Fort Lupton
Generating Station) for 150 megawatts which began on July 1, 2009. On December 2, 2011, the Association acquired Thermo Cogeneration
Partnership in a business combination which thereby resulted in the elimination of the J.M. Shafer agreement as of this date (see Note 3—
Acquisitions). Under these agreements, the Association directs the use of the contracted generating equipment over the terms of the contracts
under tolling arrangements whereby the Association provides its own natural gas for generation of electricity. These agreements are therefore
in substance leases and are accounted for as operating leases. The Association’s operating lease commitments for these gas tolling arrangements
at December 31, 2012 are as follows (thousands):
2013
2014
2015
2016
2017
Thereafter
$ 5,048
5,200
5,359
5,519
5,678
11,886
$38,690
Note 10—Related Parties
Yampa Project:
The Association acts as the operating agent for participants of the Yampa Project and related common facilities.
Basin Electric Power Cooperative (“BEPC”):
BEPC is a wholesale power supply cooperative of which the Association is a member. The Association purchased power from BEPC at a cost
of $138, $94.2 and $86.0 million in 2012, 2011 and 2010, respectively. The Association’s investment in BEPC was $69.8 and $64.3 million at
December 31, 2012 and 2011, respectively, and is included in investments in other associations. The Association’s share of BEPC capital credit
allocations was $5.5, $3.9 and $3.2 million in 2012, 2011 and 2010, respectively, and is included in capital credits from cooperatives.
National Rural Utilities Cooperative Finance Corporation:
Investments in other associations includes a $42.9 and $43.9 million investment in CFC as of December 31, 2012 and 2011, respectively. At
December 31, 2012 and 2011, the total outstanding debt owed to CFC was $136 and $155 million, respectively. The Association’s share of
CFC capital credit allocations for 2012, 2011 and 2010 was $874,000, $1.3 million and $1.4 million, respectively, and is included in capital
credits from cooperatives.
CoBank, ACB (“CoBank”):
Investments in other associations included a $4.6 and $4.3 million investment in CoBank as of December 31, 2012 and 2011, respectively. At
December 31, 2012 and 2011, the total outstanding debt owed to CoBank was $168 and $74.4 million, respectively. The Association’s share
of CoBank capital credit allocations for 2012, 2011 and 2010 was $794,000, $798,000 and $861,000, respectively, and is included in capital
credits from cooperatives.
38
2012 ANNUAL REPORT
Trapper Mining:
The Association and certain participants in the Yampa Project own Trapper Mining. Organized as a cooperative, Trapper Mining supplied
25, 28 and 23 percent of the coal for the Yampa Project in 2012, 2011 and 2010, respectively. The Association’s share of coal purchases from
Trapper Mining was $11.2, $18.5 and $15.3 million in 2012, 2011 and 2010, respectively. The Association’s membership interest in Trapper
Mining of $12.7 and $12.2 million at December 31, 2012 and 2011, respectively, is accounted for as an investment in coal mines. The
Association’s investment in Trapper Mining is recorded using the equity method. In 2012, 2011 and 2010, gains of $531,000, $714,000 and
$412,000, respectively, are included in capital credits from cooperatives.
Western Fuels Association:
WFA is a non-profit membership corporation organized for the purpose of acquiring and supplying fuel resources to its members, which
include the Association and BEPC. WFA supplies fuel to MBPP through contracts with coal companies and through its ownership in Western
Fuels-Wyoming, which owns and operates the Dry Fork Mine. The Association also receives coal supplies directly from WFA for the Escalante
Generating Station in New Mexico and spot coal for the Springerville Generating Station in Arizona. The Association’s share of coal purchases
from WFA was $71.7, $84.4 and $72.8 million in 2012, 2011 and 2010, respectively.
The Association advanced funds to WFA, through MBPP, for mine and equipment purchases and mine development costs. The fund advance
balance of $1.8 and $3.1 million at December 31, 2012 and 2011, respectively, is included in investments in coal mines. The Association’s
membership interest in WFA, including interest through MBPP in WFA, totals $1.8 and $2.0 million at December 31, 2012 and 2011,
respectively, and is included in investments in other associations. The Association’s investment in WFA is recorded using the equity method.
The 2012, 2011 and 2010 (losses)/gain of $(199,000), $49,000 and $(44,000), respectively, are included in capital credits from cooperatives.
Note 11—Employee Benefit Plans
Defined Benefit Plan:
Substantially all of the Association’s 1,517 employees participate in the National Rural Electric Cooperative Association Retirement Security
Plan (“RS Plan”) except for the 252 employees of Colowyo Coal that was acquired December 1, 2011 (see Note 3—Acquisitions). The RS 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 for compensation-retirement benefits. The plan sponsor’s Employer Identification Number is
53-0116145 and the Plan Number is 333.
A unique characteristic of a multiemployer plan compared to a single employer plan is that all plan assets are available to pay benefits to 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 Association’s contributions to the RS Plan in each of the years 2012, 2011 and 2010 represented less than 5 percent of the total contri
butions made each year to the plan by all participating employers. The Association made contributions to the RS Plan of $24.9, $24.2 and
$22.8 million in 2012, 2011 and 2010, respectively. There have been no significant changes that affect the comparability of 2012, 2011 and
2010 contributions.
The Association’s contributions to the RS Plan include contributions for substantially all of the 354 bargaining unit employees that are made
in accordance with collective bargaining agreements. Two such agreements for 333 employees expire on March 30, 2014 and another agreement
for 21 employees expires on January 17, 2016.
In the RS Plan, a “zone status” determination is not required, and therefore not determined, under the Pension Protection Act (“Act”) 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 between 65 and 80 percent funded at January 1, 2012 and January 1, 2011 based on the Act funding target and the Act
actuarial value of assets on those dates.
Because the provisions of the Act 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.
Defined Contribution Plan:
The Association has a qualified savings plan for eligible employees who may make pre-tax and after-tax contributions totaling up to 100 percent
of their eligible earnings subject to certain limitations under federal law. The Association makes no contributions for the 354 bargaining unit
employees. For all of the eligible non-bargaining unit employees, other than the 252 employees of Colowyo Coal that was acquired December
1, 2011 (see Note 3—Acquisitions), the Association contributes 1 percent of an employee’s eligible earnings. For the employees of Colowyo
Coal, the Association contributes 7 percent of an employee’s eligible earnings and also matches an employee’s contributions up to 5 percent.
The Association made contributions to the plan of $3.0 million, $895,000 and $758,000 in 2012, 2011 and 2010, respectively.
39
Postretirement Benefits Other Than Pensions:
The Association sponsors 3 medical plans for all non-bargaining unit employees of the Association. Two of the plans provide postretirement
medical benefits to full-time non-bargaining unit employees and retirees who receive benefits under those plans, who have attained age 55,
and who elect to participate. All 3 of these non-bargaining unit medical plans offer postemployment medical benefits to employees on longterm disability. The plans were unfunded at December 31, 2012, are contributory (with retiree premium contributions equivalent to employee
premiums, adjusted annually) and contain other cost-sharing features such as deductibles.
The postretirement medical benefit liability balances of $2.9 and $2.8 million at December 31, 2012 and 2011, respectively, are included in
accumulated postretirement benefit and postemployment obligations. In 2010, there was a $4.7 million actuarial gain determined by an
actuarial study performed in 2010 (actuarial studies are performed every 5 years or earlier if plan facts warrant it). $4.2 million of the gain was
not recognized in net margins during 2010 because it was in excess of 10 percent of the projected benefit obligation. Instead, it was reported
separately as a component of other comprehensive income at December 31, 2010 (as shown on the statements of comprehensive income). The
unrecognized gain is amortized over the average remaining service lives of the active plan participants which results in an annual recognition
of the gain of $358,000 beginning in 2011.
The postemployment medical benefit liability balance of $291,000 at December 31, 2012 and 2011 is included in accumulated postretirement
benefit and postemployment obligations. The liability balance was determined by an actuarial study performed in 2010 (actuarial studies are
performed every 5 years or earlier if plan facts warrant it).
Note 12—Commitments and Contingencies
Sales:
The Association has delivery obligations under resource-contingent firm power sales contracts with PSCO totaling 125 megawatts in the
summer season and 175 megawatts in the winter season. These contracts expire in 2016 and 2017. Also with PSCO, the output of the two
gas turbines at Knutson Generating Station and one gas turbine at the Limon Generating Station has been sold under two contracts for a
total of 210 megawatts in tolling capacity sales that expire in 2016. The tolling arrangements at Knutson and Limon are accounted for as
operating leases and the lease revenues are reflected in other operating revenue on the statements of operations. The Limon turbine contract
was suspended for a period of four years beginning in May 2009 and the Knutson turbine contract was suspended for a period of three years
beginning in May 2010 to allow the Association to utilize the output of the turbines. Both turbine contracts resume with PSCO under the
original tolling arrangements for the period May 1, 2013 to April 30, 2016. Tri-State also has an agreement to sell 122 megawatts in tolling
capacity to PSCO through June 30, 2019 from the J.M. Shafer Generating Station (formerly known as the Fort Lupton Generating Station—
see Note 3—Acquisitions).
In addition, the Association has (1) a resource-contingent firm power sales contract of 100 megawatts to Salt River Project through August 31,
2036, (2) a firm power sales contract committing up to 13 megawatts to BEPC through 2025, (3) a resource-contingent firm power sales contract with PacifiCorp committing 25 megawatts through 2020, (4) a resource-contingent firm power sales contract with Shell Energy North
America of 50 megawatts through September 30, 2014 and (5) a resource-contingent tolling power sales contract with Shell Energy North
America of 40 megawatts from the Pyramid Generating Station through September 30, 2014. The tolling contract at Pyramid is accounted
for as an operating lease and the lease revenue is reflected in other operating revenue on the statements of operations.
Purchase Requirements:
The Association is committed to purchase coal for its generating plants under long-term contracts that expire between 2014 and 2034. These
contracts require the Association to purchase a minimum quantity of coal at prices that are subject to escalation clauses that reflect cost
increases incurred by the suppliers and market conditions. The projection of contractually committed purchases is based upon estimated
future prices. At December 31, 2012, the annual minimum coal purchases under these contracts are as follows (thousands):
2013
2014
2015
2016
2017
Thereafter
$109,157
112,669
80,833
84,865
88,837
324,658
$801,019
40
2012 ANNUAL REPORT
Indemnities:
The Association agreed to indemnify certain lessors and purchasers of the tax benefits under the safe harbor leases (see Note 2—Deferred
Equity Note) should certain disqualifying events occur, the most significant being the failure of the Association to maintain its status as a
taxable entity. Certain other safe harbor leases, not acquired by the Association, also contain indemnity responsibilities that were assumed
in 1992. Should a disqualifying event occur related to 2012 or prior, specified payments must be made to the lessors and purchasers of $13.3
million, decreasing ratably through expiration in 2024.
Environmental:
The Association’s electric generation facilities are subject to various operating permits and must operate within guidelines imposed by numerous
environmental regulations. The Association believes these facilities are currently in compliance with such regulatory and operating permit
requirements with one exception. At the Nucla Generating Station, a deviation of the operating permit regarding Emission Unit P106
occurred in the fall of 2011. This deviation has been addressed and the facility is currently in compliance with the operating permit. The
Association expects the State of Colorado to commence an enforcement action with respect to this deviation but no such action has yet been
taken. The Association cannot predict the outcome of any such action.
Deregulation:
The operating environment of the electric utility industry has moved toward partially regulated competition with the passage of the 1992
Energy Policy Act and subsequent Federal Energy Regulatory Commission orders that deregulate sales among power resellers. As a result,
end-user deregulation was left to the states, and the Association is actively monitoring proposed legislation. The effects of potential legislation
on the financial position or results of operations of the Association are not known at this time.
Legal:
On October 19, 2004, WFA and BEPC filed a complaint with the Surface Transportation Board (“STB”) alleging that the shipping rates
instituted by the BNSF Railway Company (“BNSF”) for the delivery of coal to the Laramie River Station were unjust and unreasonable.
On July 27, 2009, the STB issued its final decision, upholding the complaint and ordering refunds and shipping rate reductions to WFA and
BEPC. On September 2, 2009, BNSF appealed the STB decision to the United States Court of Appeals for the DC Circuit. Notwithstanding
the appeal, BNSF refunded certain amounts and reduced shipping rates. Those reductions were passed on to WFA’s and BEPC’s members,
including the Association. However, those reductions are subject to refund in the event BNSF is ultimately successful in its appeal. Due to
uncertainties regarding the ultimate outcome of this matter, the Association did not recognize the benefit of the receipt of $29.4 million in
2009 in the consolidated statements of operations and still has not as of December 31, 2012. Instead, the $29.4 million was recorded as a
liability and is included in deferred credits and other liabilities at December 31, 2012 and 2011. The receipt of the cash in 2009 was reflected
in operating activities-other on the consolidated statements of cash flows. To the extent that the issue related to the cash receipt is ultimately
resolved in favor of the Association, the benefit will be recorded as a reduction in fuel expense at that time. The Court of Appeals affirmed
the District Court Decision on May 11, 2010 but remanded a single technical issue to the STB for reconsideration. On or about December 2,
2010, BNSF filed a Petition for Certiorari with the United States Supreme Court. On May 16, 2011, the Supreme Court denied the Petition
for Certiorari. The issue remanded to the STB is pending. The Association is unable to project the outcome of this matter.
On September 28, 2009, five of the Association’s Nebraska members filed suit in the United States District Court for the District of Nebraska
alleging that the Association, inter alia, had breached its member contracts with those five members. The suit seeks a separate rate to be
applied to the five members and/or an order of the Court permitting the five members to withdraw from the Association on terms to be
determined by the Court. On August 19, 2010, the Nebraska court granted the Association’s motion and transferred venue of the case to the
District of Colorado. The Association denies the claims and intends to assert all available defenses. The Association is unable to project the
outcome of the litigation.
On October 19, 2012, the Association gave notice, as required by New Mexico statutes, to the New Mexico Public Regulation Commission
(“NMPRC”) of its new wholesale rates which were scheduled to become effective on January 1, 2013. The rates would have increased revenue
collected from the Association’s 44 member systems by approximately 4.9 percent and from its 12 New Mexico member systems by approximately 6.7 percent. On November 7, 2012, Continental Divide Electric Cooperative, Inc. and Kit Carson Electric Cooperative, Inc. filed
protests of the Association’s rates. On November 8, 2012, Springer Electric Cooperative did the same. On December 20, 2012, the NMPRC
suspended the rate filing in New Mexico and appointed a Hearing Examiner to conduct a hearing and establish reasonable Rate Schedules
pursuant to New Mexico statutes. The Association expects a final decision by the NMPRC by the end of 2013. On January 25, 2013, the
Association made an additional filing at the NMPRC seeking interim rate recovery from its New Mexico member systems during the pendency
of the NMPRC proceedings on the original rate filing. NMPRC action on the interim rate recovery filing is pending. Also on January 25,
2013, the Association filed a Complaint for Declaratory and Injunctive Relief in the Federal District Court in New Mexico asking the Court
to declare the actions of the NMPRC to be in violation of the Commerce Clause of the United States Constitution. The Association intends
to vigorously pursue rate recovery and its Federal challenge to the actions of the NMPRC. The Association cannot predict the outcome of
these matters.
41
Tri-State/Member System Consolidated Financial Data
(Unaudited)
(Thousands)
Total
Assets
Equity
Net
Margins
Equity as %
of Assets
2011
Members
Tri-State
Less eliminations
$3,442,389 $1,620,956 $114,156
4,190,973
879,455
69,934
(858,657)
(759,917)
(69,934)
47.1
21.0
System consolidation
$6,774,705
25.7
2010
2009
2008
2007
Members only (Thousands)
Revenues
Operating margins
Net margins
Plant in service (net)
Total assets
Long-term debt
Equity
Equity as a % of assets
Average retail rate (mills/kWh)
6,310,130
6,114,287
4,804,894
4,630,059
$1,740,494 $114,156
1,659,874
1,570,976
1,301,958
1,200,272
115,773
130,560
138,924
143,862
2010
2009
2008
2007
$1,437,195 $1,355,178
33,274
23,530
115,773
130,560
2,124,009
2,061,546
3,320,321
3,171,371
1,403,054
1,363,741
1,536,068
1,441,528
46.3
45.5
98.9
99.1
$1,290,934
36,664
138,924
1,958,336
2,934,692
1,275,200
1,302,436
44.4
95.9
$1,148,722
37,914
143,862
1,840,024
2,729,313
1,201,665
1,200,219
44.0
89.8
2011
$1,473,907
34,163
114,156
2,187,086
3,442,389
1,446,019
1,620,956
47.1
99.3
26.3
25.7
27.1
25.9
Source: Members’ RUS Financial and Operating Reports. Due to the unavailability of the 2012 Member Financial information,
the numbers being reported here are the 2011 and prior years’ information.
42
Tri-State Generation and Transmission Association, Inc. is committed to a policy of considering individuals without
regard to race, color, sex, sexual orientation, religion, national origin or age in decisions involving hiring, promoting,
transferring, training or any other terms or conditions of employment. Furthermore, Tri-State will take affirmative
action in the hiring, promoting, transferring and training of special disabled veterans of the Vietnam era and disabled
individuals.
Annual Report Design by Curran & Connors, Inc. / www.curran-connors.com
P.O. Box 33695, Denver, CO 80233 / www.tristate.coop

Cooperative Value - Tri-State Generation and Transmission

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