SHINING
STRONG
A N N U A L R E P O R T 2 0 1 4
SHINING
Roanoke’s signature signs, streaming through the night, beckoning travelers near and far
for a cup of H&C Coffee, to come EAT at Texas Tavern or to stop for a drink of Dr Pepper
beneath the Mill Mountain Star that lights up the city, have been luminary landmarks for
half a century in the city that Roanoke Gas Company calls home. Like natural gas, which
is enjoying a huge resurgence of popularity as a clean, efficient and affordable energy
source, Roanoke’s neon classics are bright and familiar points of light that have seen
us through the years.
Shining strong: It’s a sign of the times.
R G C R E S O U R C E S , I N C .
STRONG
Year Ending September 30
2014 2013 2012
OPERATING REVENUE -
NATURAL GAS
$ 73,865,487
$ 62,024,174
$ 57,657,940
OTHER REVENUE
$ 1,150,647
$ 1,181,492
$ 1,141,747
NET INCOME
$ 4,708,440
$ 4,262,052
$ 4,296,745
BASIC EARNINGS PER SHARE
$ 1.00
$ 0.91
$ 0.92
DIVIDENDS PER SHARE -
CASH
$ 0.74
$ 1.72
$ 0.70
NUMBER OF CUSTOMERS -
NATURAL GAS
58,553
58,238
57,941
TOTAL NATURAL GAS
DELIVERIES - DTH
10,087,651
9,408,894
8,317,496
TOTAL ADDITIONS TO PLANT
$ 14,715,428
$ 9,977,433
$ 8,683,658
A N N U A L R E P O R T 2 0 1 4
1
“WE ARE EXCITED
TO BE A PART OF THE
GROWING NATURAL
GAS INDUSTRY AND
THE PURSUIT OF
POTENTIAL GROWTH
OPPORTUNITIES IT
MAY BRING TO OUR
COMPANY.”
PRESIDENT & CEO
John D’Orazio
In my first full year as President and CEO, I am pleased to report 2014
earnings of $4,708,440 or $1.00 per share outstanding compared
with $0.91 per share last year, a 10% improvement. I am also pleased
to report that our Board of Directors approved an annualized dividend
increase from $0.74 per share to $0.77 per share effective with the
February 1, 2015, quarterly dividend payment. The February dividend
will reflect 70 years of continuous quarterly dividend payments, and
18 annual dividend increases in the past 19 years.
2
R G C R E S O U R C E S , I N C .
TEXAS TAVERN
Retro Roanoke — that’s the Texas
Tavern. With its vintage, arrow-
shaped “EAT” sign and neon tubing
shining bright all night, locals have
been flocking to the counter-service
restaurant, which seats “1,000
people . . . 10 at a time,” since 1930.
The beloved “TT” is especially
known for its chili, whose recipe
dates back almost a century when
founder Nick Bullington discovered
it while traveling for the Ringling
Brothers Circus in San Antonio,
Texas. The diner, now run by
Nick’s great-grandson Matt, whips
up classic short-order food. As
one reviewer wrote, “The flavor is
definitely local but the experience
transcends generations.”
A N N U A L R E P O R T 2 0 1 4
3
DR PEPPER SIGN
In the 1950s, Roanoke was named
the “Dr Pepper Capital of the World,”
breaking world records for its resi-
dents’ impressive consumption. And
so it was fitting that the soft drink
company helped finance restoration
of the 30-foot sign that has delighted
folks in downtown Roanoke since the
mid-1940s. With its whimsical 10, 2
and 4, signaling the times of day that
call for a Dr Pepper pick-me-up, the
sign now sits atop the Legg Mason
building across the street from the
H&C Coffee sign.
MILL MOUNTAIN
STAR
The Mill Mountain Star, the world’s
largest freestanding illuminated
manmade star, rose high above
the city in 1949. Conceived by the
Roanoke Merchants Association and
enhanced by $100,000 in electrical
upgrades in 2006, the star measures
a massive 88.5 feet and encompasses
2,000 feet of neon tubing. Earning
Roanoke the nickname “Star City of
the South,” the sign burns every night
until midnight. It’s a beacon for the
city, visible for 60 miles in the air.
4
Operationally, 2014 was a
strong and busy year. The
weather was 9% colder than
the 30-year average and our
total natural gas deliveries
exceeded 10 million deka-
therms. Industrial demand
increased by 6% over last year
and we anticipate this higher
level of natural gas use to
continue next year. We are
also excited to provide natural
gas service to a new packaging manufacturer,
Ardagh Group, which opened a $93 million
metal packaging plant with the capability of
producing 1.7 billion cans a year.
We invested a record $14.7 million in capital
improvements in 2014 and plan to invest
approximately $13.5 million in fiscal 2015.
We continue to aggressively modernize our
distribution system. In 2014, we replaced
13.6 miles of cast iron and bare steel pipe
with polyethylene pipe. In 1991, cast iron and
bare steel pipe accounted for approximately
25% of our distribution system. At the end
of fiscal 2014, it represents less than 2%.
Based on the estimated replacement rate, we
anticipate replacing all remaining bare steel
and cast iron pipe by the end of 2016, further
enhancing safety and system reliability. Once
we complete the replacement of our bare
steel and cast iron mains, our efforts will
shift to replacing all pre-1973 plastic mains
with current polyethylene pipe. This infra-
structure replacement program is forecast
to be completed in fiscal 2019. In 2014, we
replaced and upgraded one of our primary
gas transfer stations and are in the final
stages of replacing a critical piece of equip-
ment at our liquefied natural gas facility that
is used for peak shaving during extremely
cold periods.
“INDUSTRIAL DEMAND
INCREASED BY 6% OVER
LAST YEAR AND WE
ANTICIPATE THIS HIGHER
LEVEL OF NATURAL GAS USE
TO CONTINUE NEXT YEAR.”
As the economy continues to gradually
improve, we are experiencing improved
customer growth. In 2014, new customer
additions increased 43% over last year. The
new construction segment increased 7%, the
conversion segment where existing homes
or businesses converted to natural gas from
either propane, fuel oil or electric increased
17%, and the balance of the increase was
derived from the conversion of an apartment
complex to individual gas meters.
We had an active year from a regulatory
prospective. The rate case filed in September
2013 was settled favorably with the Virginia
State Corporation Commission (SCC) in May
2014, at $887,000 with an authorized return
on equity of 9.75%. We filed an updated
depreciation study with the SCC in June and
received approval of the new depreciation
rates in September, resulting in a slight
decrease in annual depreciation expense.
We filed and received approval on an amend-
ment to a separate regulatory infrastructure
replacement plan designed to recover
the increased investment carrying costs
and depreciation expense associated with
future planned infrastructure replacements
through calendar year 2018. This includes
modernization of our distribution system,
replacement of our gas transfer station on
A N N U A L R E P O R T 2 0 1 4
5
“ON A NATIONAL LEVEL, NATURAL GAS INDUSTRY DATA
INDICATES THAT WE HAVE A NATURAL GAS SUPPLY OF OVER
100 YEARS. THIS ABUNDANT AND INCREASINGLY ACCESSIBLE
SUPPLY HAS CREATED LOW AND STABLE PRICES ON BOTH A
NEAR AND INTERMEDIATE TERM BASIS.”
the interstate pipeline, and replacement of a
key component at our liquefied natural gas
facility. Last, we filed and received approval
from the SCC for refinancing our existing
long-term debt, which will reduce our annual
interest expense going forward.
On a national level, natural gas industry data
indicates that we have a natural gas supply of
over 100 years. This abundant and increas-
ingly accessible supply has created low and
stable prices on both a near and intermediate
term basis. Production continues to increase
in the various shale formations around
the country as natural gas exploration and
production companies continue to improve
drilling and fracking technologies. As pro-
duction has increased, so has the demand for
new pipelines to move this increased supply
to market. Interstate pipeline companies are
investing billions of dollars constructing new
pipelines and modifying existing pipelines to
make them bi-directional so they can effi-
ciently move gas as future demand increases.
In the Commonwealth of Virginia, two pipe-
lines are proposed: Atlantic Coast Pipeline
and the Mountain Valley Pipeline. Both are
designed to move gas from the Marcellus
and Utica shale formations to the Southeast.
The Mountain Valley Pipeline, if constructed,
may provide future opportunities to expand
our footprint in Virginia to areas that cur-
rently do not have access to natural gas.
We are excited to be part of the growing
natural gas industry and the pursuit of
potential growth opportunities it may bring to
our Company. I look forward to reporting to
you at the end of 2015 on what I anticipate to
be another year of solid performance.
On behalf of our dedicated employees and
the Board of Directors, I thank you for your
continued interest in our operations and
your continuing decision to invest in
RGC Resources.
Sincerely,
John D’Orazio
President & CEO
6
R G C R E S O U R C E S , I N C .
H&C COFFEE
SIGN
The colorful H&C Coffee sign,
erected in 1946, still shines whim-
sically through the Roanoke night.
Refurbished through the efforts
of Downtown Roanoke Inc., along
with public and private donors, the
fabulous neon sign now sits grandly
on top of the old Shenandoah Hotel,
blinking on and off as coffee appears
to pour out of a curvy green spout.
Like the Dr Pepper sign, H&C Coffee,
a Roanoke-based brand dating back
to 1927, was moved to remain visible
to travelers on Interstate 581.
A N N U A L R E P O R T 2 0 1 4
7
BOARD OF DIRECTORS
LEFT TO RIGHT: John B. Williamson, III; Nancy Howell Agee; George W. Logan; J. Allen Layman; Raymond D. Smoot, Jr.;
Maryellen F. Goodlatte; S. Frank Smith; John S. D’Orazio; (Abney S. Boxley, III not pictured)
8
R G C R E S O U R C E S , I N C .
OFFICERS AND BOARD OF DIRECTORS
OFFICERS
John B. Williamson, III
ChaIrman Of thE BO arD 1, 2
John S. D’Orazio
PrESIDEnt anD
ChIEf ExECutIvE OffICEr 1, 2, 3, 4
DIRECTORS
nancy howell agee
PrESIDEnt anD
ChIEf ExECutIvE OffICEr
Carilion Clinic
DIrEC tOr 1, 2
abney S. Boxley, III
PrESIDEnt anD
ChIEf ExECutIvE OffICEr
Boxley Materials Company
DIrEC tOr 1
John S. D’Orazio
PrESIDEnt anD
ChIEf ExECutIvE OffICEr
RGC Resources, Inc. 1, 2
Paul W. nester
vICE PrESIDEnt, trEaSurEr anD
ChIEf fInanCIal OffICEr 1, 2, 3, 4
howard t. lyon
aSSIStant SECrEtary anD
aSSIStant trEaSurEr 1, 2, 3, 4
Dale P. lee
vICE PrESIDEnt anD
SECrEtary 1, 2, 3, 4
robert l. Wells, II
vICE PrESIDEnt,
InfOrmatIOn tEChnOl Ogy 1, 3, 4
maryellen f. goodlatte
attOrnEy anD PrInCIP al
Glenn Feldmann Darby & Goodlatte
DIrEC tOr 1, 2
S. frank Smith
COnSultant
Alpha Coal Sales Company, LLC
DIrEC tOr 1, 2
J. allen layman
PrIvatE InvESt Or
DIrEC tOr 1, 2
george W. logan
PrInCIP al
Pine Street Partners, llc
faCulty
University of Virginia
Darden Graduate School of Business
DIrEC tOr 1, 2
raymond D. Smoot, Jr.
SEnIOr fEll OW
Virginia Tech Foundation, Inc.
DIrEC tOr 1
John B. Williamson, III
ChaIrman Of thE BO arD 1, 2
SUBSIDIARY BOARD OF DIRECTORS
John S. D’Orazio
PrESIDEnt anD
ChIEf ExECutIvE OffICEr
RGC Resources, Inc.
ChaIrman anD DIrEC tOr 3, 4
Dale P. lee
vICE PrESIDEnt anD
SECrEtary
RGC Resources, Inc.
DIrEC tOr 3, 4
Paul W. nester
vICE PrESIDEnt, trEaSurEr anD
ChIEf fInanCIal OffICEr
RGC Resources, Inc.
DIrEC tOr 3, 4
robert l. Wells, II
vICE PrESIDEnt,
InfOrmatIOn tEChnOl Ogy
RGC Resources, Inc.
DIrEC tOr 3, 4
1 RGC Resources, Inc.
2 Roanoke Gas Company
3 Diversified Energy Company
4 RGC Ventures of Virginia, Inc.
A N N U A L R E P O R T 2 0 1 4
9
SELECTED FINANCIAL DATA
YE AR ENDING SEPTEMBER 30
2014
2013
2012
2011
2010
Operating Revenues
$
75,016,134
$
63,205,666
$
58,799,687
$
70,798,871
$
73,823,914
Gross Margin
Operating Income
Net Income
Basic Earnings Per Share
Cash Dividends Declared
Per Share
Book Value Per Share
$
$
$
29,337,089
27,602,891
26,933,097
27,269,566
26,440,273
9,681,868
8,795,055
8,786,535
9,313,046
8,982,181
4,708,440
4,262,052
4,296,745
4,653,473
4,445,436
1.00
$
0.91
$
0.92
$
0.74
$
1.72
$
0.70
$
1.01
0.68
$
$
0.98
0.66
11.02
$
10.51
$
10.85
$
10.55
$
10.18
Average Shares Outstanding
4,715,478
4,698,727
4,647,439
4,592,713
4,514,262
Total Assets
Long-Term Debt
(Less Current Portion)
Stockholders’ Equity
$
139,320,722
$
124,526,701
$
129,756,338
$
125,549,049
$
120,683,316
30,500,000
13,000,000
13,000,000
13,000,000
28,000,000
52,020,847
49,502,422
50,682,930
48,785,778
46,309,747
Shares Outstanding at Sept. 30
4,720,378
4,709,326
4,670,567
4,624,682
4,548,864
1 0
R G C R E S O U R C E S , I N C .
forward-looking statements
This report contains forward-looking statements that
relate to future transactions, events or expectations.
RGC Resources, Inc. (“Resources” or the “Company”)
may publish forward-looking statements relating to such
matters as anticipated financial performance, business
prospects, technological developments, new products,
research and development activities and similar matters.
These statements are based on management’s current
expectations and information available at the time of
such statements and are believed to be reasonable and
are made in good faith. The Private Securities Litigation
Reform Act of 1995 provides a safe harbor for forward-
looking statements. In order to comply with the terms
of the safe harbor, the Company notes that a variety of
factors could cause the Company’s actual results and
experience to differ materially from the anticipated
results or expectations expressed in the Company’s
forward-looking statements. The risks and uncertainties
that may affect the operations, performance, development
and results of the Company’s business include, but are
not limited to those set forth in the following discussion
and within Item 1A “Risk Factors” of this Annual Report
on Form 10-K. All of these factors are difficult to predict
and many are beyond the Company’s control. Accordingly,
while the Company believes its forward-looking
statements to be reasonable, there can be no assurance
that they will approximate actual experience or that the
expectations derived from them will be realized. When
used in the Company’s documents or news releases, the
words “anticipate,” “believe,” “intend,” “plan,” “estimate,”
“expect,” “objective,” “projection,” “forecast,” “budget,”
“assume,” “indicate” or similar words or future or
conditional verbs such as “will,” “would,” “should,” “can,”
“could” or “may” are intended to identify forward-looking
statements.
Forward-looking statements reflect the Company’s
current expectations only as of the date they are
made. The Company assumes no duty to update these
statements should expectations change or actual results
differ from current expectations except as required by
applicable laws and regulations.
A N N U A L R E P O R T 2 0 1 4
11
management’s discussion & analysis
OVERVIEW
Resources is an energy services company primarily
engaged in the regulated sale and distribution of natural
gas to approximately 58,600 residential, commercial
and industrial customers in Roanoke, Virginia and the
surrounding localities, through its Roanoke Gas Company
(“Roanoke Gas”) subsidiary. Resources also provides
certain unregulated services through Roanoke Gas
and utility consulting and information system services
through RGC Ventures of Virginia, Inc., which operates
as The Utility Consultants and Application Resources.
The unregulated operations represent less than 3% of
revenues and margins of Resources.
The utility operations of Roanoke Gas are regulated by
the Virginia State Corporation Commission (“SCC”), which
oversees the terms, conditions, and rates to be charged
to customers for natural gas service, safety standards,
extension of service, accounting and depreciation.
The Company is also subject to federal regulation
from the Department of Transportation in regard to
the construction, operation, maintenance, safety and
integrity of its transmission and distribution pipelines.
The Federal Energy Regulatory Commission regulates
prices for the transportation and delivery of natural gas
to the Company’s distribution system and underground
storage services. The Company is also subject to other
regulations which are not necessarily industry specific.
The Company is committed to the safe and reliable
delivery of natural gas to its customers. Since 1991, the
Company has placed an emphasis on the modernization
of its distribution system through the renewal and
replacement of its cast iron and bare steel natural gas
distribution pipelines. With recent regulatory actions
placing a greater emphasis on pipeline safety, the
Company continues to focus its efforts on completing
its renewal and replacement program. Management
anticipates replacing all remaining cast iron and bare
steel pipe within the next three years.
information with a malicious intent to corrupt data, cause
operational disruptions, or compromise information.
Management believes it has taken reasonable security
measures to protect these systems from cyber security
attacks and other types of breaches; however, there
can be no guarantee that a breach will not occur. In the
event of a breach, the Company will execute its Security
Incident Response Plan to assist with managing the
incident. The Company also maintains cyber-insurance
coverage to mitigate financial implications resulting from
a breach of confidential information.
Over 97% of the Company’s revenues are derived through
the regulated operations of Roanoke Gas primarily
associated with the sale and delivery of natural gas to its
customers. The SCC authorizes the rates and fees that
the Company charges its customers for these services.
These rates are designed to provide the Company with
the opportunity to recover its gas and non-gas expenses
and to earn a reasonable rate of return for shareholders
based on normal weather. Normal weather refers to the
average number of heating degree days (an industry
measure by which the average daily temperature falls
below 65 degrees Fahrenheit) over the previous
30-year period.
The Company’s business is seasonal in nature and
weather sensitive as a majority of natural gas sales are
for space heating during the winter season. Volatility in
winter weather and the commodity price of natural gas,
can impact the effectiveness of the Company’s rates in
recovering its costs and providing a reasonable return
for its shareholders. In order to mitigate the effect of
weather variations, the Company has certain approved
rate mechanisms that help provide stability in earnings.
These mechanisms include a weather normalization
adjustment factor, inventory carrying cost revenue and a
SAVE adjustment rider.
The Company is also dedicated to the safeguarding of
its information technology systems. These systems
contain confidential customer, vendor and employee
information as well as important financial data. There
is risk associated with the unauthorized access of this
The weather normalization adjustment mechanism
(“WNA”) reduces the volatility in earnings due to the
variability in temperatures during the heating season. The
WNA is based on a weather measurement band around
the most recent 30-year temperature average. The WNA
provides the Company with a level of earnings protection
1 2
RGC RESOURCES, INC. when weather is warmer than normal and provides its
customers with price protection when the weather is
colder than normal. Through March 31, 2014, the WNA
provided for a weather band of 3% above and below the
30-year average, whereby the Company would bill its
customers for the lost margin (excluding gas costs) for
the impact of weather that was more than 3% warmer
than normal or refund customers the excess margin
earned for weather that was more than 3% colder than
normal. The annual WNA period extends from April to
March. For the WNA periods ending March 31, 2014,
2013 and 2012, the number of heating degree days were
10% colder than normal, less than 3% warmer than
normal and 22% warmer than normal, respectively. As a
result, the Company refunded customers approximately
$707,000 in excess margin in fiscal 2014 and billed
customers approximately $1,747,000 in additional margin
in fiscal 2012. No billing or refunds were required in fiscal
2013 as the number of heating degree days fell within the
3% band. Effective with the new WNA period beginning
April 1, 2014, the 3% weather band was eliminated and
the WNA is now based strictly on the variations from
normal. At September 30, 2014, the number of heating
degree days for the six month period was less than the
30-year average and the Company accrued approximately
$144,000 in additional margin. Additional information on
the WNA is provided under the Regulatory Affairs section.
The Company also has an approved rate structure in place
that mitigates the impact of financing costs of its natural
gas inventory. Under this rate structure, Roanoke Gas
recognizes revenue for the financing costs, or “carrying
costs”, of its investment in natural gas inventory. The
carrying cost revenue (“ICC”) factor applied to inventory is
based on the Company’s weighted-average cost of capital
including interest rates on short-term and long-term debt
and the Company’s authorized return on equity.
During times of rising gas costs and rising inventory
levels, the Company recognizes revenues to offset higher
financing costs associated with higher inventory balances.
Conversely, during times of decreasing gas costs and
declining inventory balances, the Company recognizes
less carrying cost revenue as financing costs are lower.
Although the total cost of natural gas in storage, as well
as the cost per decatherm, at September 30, 2014 was
higher than the cost in storage at September 30, 2013, the
average balance during the year was down by more than
4% due to greater level of storage withdrawals during a
much colder 2013-2014 winter season. In addition, the
ICC factor declined by 2%, resulting in a reduction in ICC
revenues of $58,000. Fiscal 2013 reflected a $299,000
reduction in ICC revenues due to a 14% lower average
balance of natural gas in storage as compared to fiscal 2012.
1 3
ANNUAL REPORT 2014 Generally, as investment in natural gas inventory
increases so does the level of borrowing under the
Company’s line-of-credit. However, as the carrying
cost factor used in determining carrying cost revenues
is based on the Company’s weighted-average cost of
capital, carrying cost revenues do not directly correspond
with incremental short-term financing costs. Therefore,
when inventory balances decline due to a reduction in
commodity prices, net income will decline as carrying
cost revenues decrease by a greater amount than short-
term financing costs decrease. The inverse occurs when
inventory costs increase.
The Company’s non-gas rates provide for the recovery
of non-gas related expenses and a reasonable return to
shareholders. These rates are determined based on the
filing of a formal rate application with the SCC utilizing
historical information including investment in natural
gas facilities. Generally, investments related to extending
service to new customers are recovered through the
non-gas rates currently in place. The investment in
replacing and upgrading existing infrastructure is not
recoverable until a formal rate application is made to
include the additional investment and new non-gas rates
are approved. The SAVE (“Steps to Advance Virginia’s
Energy”) Plan and Rider provides the Company with the
ability to recover costs related to these investments on
a prospective basis rather than on a historical basis.
Additional information regarding the SAVE Rider is
provided under the Regulatory Affairs section.
The economic environment has a direct correlation with
business and industrial production, customer growth and
natural gas utilization. The local economy continues to
show signs of improvement from the economic downturn
that began in 2008, as industrial production activities
and the related interruptible and transportation sales to
support those activities have returned to pre-2008 levels.
Although there are signs of improvement, residential
construction and housing starts continue to remain
below historical levels. If economic stagnation were
to return, industrial activity and new customer growth
could be negatively impacted. In addition to economic
considerations, natural gas consumption continues to be
affected by technological and efficiency improvements in
heating equipment.
CAPITALIZATION
ratios
(In Percentages)
79.6
79.2
62.3
63.5
63.0
80
60
40
37.7
36.5
37.0
20.4
20.8
20
0
10
11
12
13
14
Long-Term Debt
Equity
1 4
RGC RESOURCES, INC. RESULTS OF OPERATIONS
Fiscal year 2014 compared with Fiscal year 2013
The table below reflects operating revenues, volume activity and heating degree-days.
operating revenues
YE AR ENDING SEPTEMBER 30
2014
2013
increase / (decrease)
percentage
Gas Utilities
Other
$ 73,865,487
$ 62,024,174
$ 11,841,313
1,150,647
1,181,492
(30,845)
Total Operating Revenues
$ 75,016,134
$ 63,205,666
$ 11,810,468
19%
-3%
19%
delivered volumes
YE AR E NDING S EPTEMBER 30
2014
2013
increase
percentage
Regulated Natural Gas (DTH)
Residential and Commercial
Transportation and Interruptible
7,005,920
3,081,731
6,498,783
2,910,111
507,137
171,620
Total Delivered Volumes
10,087,651
9,408,894
678,757
Heating Degree Days (Unofficial)
4,351
4,001
350
8%
6%
7%
9%
Total gas utility operating revenues for the year ended
September 30, 2014 increased by 19% from the year
ended September 30, 2013. The increase in gas revenues
was primarily attributable to a combination of a 7%
increase in total delivered natural gas volumes, a 30%
per decatherm increase in the average commodity price
of natural gas, implementation of a non-gas rate increase
and higher SAVE Plan revenues. The increase in delivered
volumes was driven by the colder winter heating season
where total heating degree days increased by 9% over
fiscal 2013 and were above the 30-year average by the
same percentage. Transportation and interruptible
volumes, which are primarily driven by production
activities rather than weather, increased by 6%. Other
revenues decreased by 3% due to the completion of
a one-time project during the prior year more than
offsetting increases in the level of certain other contract
services during the current year.
1 5
ANNUAL REPORT 2014 gross margin
YE AR ENDING SEPTEMBER 30
2014
2013
increase
percentage
Gas Utility
Other
$ 28,774,213
$ 27,108,112
$ 1,666,101
562,876
494,779
68,097
Total Gross Margin
$ 29,337,089
$ 27,602,891
$ 1,734,198
6%
14%
6%
Regulated natural gas margins from utility operations
increased by 6% from fiscal 2013, primarily as a result
of higher residential and commercial sales volumes,
the implementation of a non-gas rate increase and
the addition of the SAVE Plan rider. Residential and
commercial volumes (which are strongly correlated to
the weather) increased due to the much colder winter
season. The higher margins generated by the increased
residential and commercial volume were mostly offset
by a net WNA refund of $563,000 recognized in fiscal
2014. The Company also implemented a non-gas rate
increase effective November 1, 2013 and an increased
SAVE Plan Rider beginning January 1, 2014. The non-
gas rate increase was designed to provide approximately
$887,000 in additional annual non-gas revenues. The
implementation of the increased non-gas rates in
November accounted for approximately $422,000 of the
increase in customer base charges, a flat monthly fee
billed to each natural gas customer, and $474,000 of the
additional volumetric revenue. The SAVE Plan Rider, as
discussed in more detail in the Regulatory Affairs section
below, provided an additional $123,000 in margin. ICC
revenues continued to decline with a $58,000 reduction
in fiscal 2014 compared to fiscal 2013 due to the larger
storage withdrawals and lower ICC factor.
Other margins, consisting of non-utility related services,
increased by $68,097 due to an increased level of activity
under one of the contracted services. The service
contracts that comprise most of the non-utility related
activities are subject to annual or semi-annual renewal
provisions and the potential exists that these contracts
may not be renewed or extended by the customer. In
addition, the level of activity under these contracts will
fluctuate based on customer requirements.
The changes in the components of the gas utility margin
are summarized below:
net utility margin increase
Customer Base Charge
$
659,671
Volumetric
SAVE Plan
WNA
Carrying Cost
Other
Total
1,493,353
123,199
(563,187)
(58,303)
11,368
$
1,666,101
1 6
RGC RESOURCES, INC.
operations and maintenance expense –
Operations and maintenance expenses increased by
$529,789, or 4%, in fiscal 2014 compared with fiscal 2013
primarily due to higher labor costs, contracted services,
bad debt expense and corporate insurance expense more
than offsetting significant reductions in employee benefit
costs and greater capitalization of Company overheads
on construction projects and LNG (liquefied natural
gas) production. Labor costs and contracted services
increased by $1,128,000 primarily due to a full year of
increased operations staffing, timing of pipeline right-
of-way clearing, a full year of costs related to an SCC
mandated meter installation inspection and remediation
program, expenses related to updating the Company’s
corrosion control processes, benefit consulting services
and network services support and training. Bad debt
expense increased by approximately $64,000 related to
much higher customer billings due to a colder winter
heating season. Corporate property and liability insurance
increased by $93,000 due to a combination of higher
premiums and increased general liability coverage limits.
Insurance premiums are expected to increase in fiscal
2015 as well but at a lesser amount. These higher costs
were partially offset by a $605,000 reduction in employee
benefit expenses, specifically in the defined benefit
pension plan (“pension plan”) and the postretirement
medical and life insurance plan (“postretirement plan”).
These actuarially determined expenses declined in fiscal
2014 due to a combination of a higher discount rate for
valuing both plans’ liabilities at September 30, 2013 and
strong investment performance of both plans’ assets.
More information on these plans and the impact on the
financial statements are provided under the Pension
and Postretirement Benefits section of the Critical
Accounting Policies and Estimates below and in Note
6 of the financial statements. In addition, $339,000 of
additional overheads was capitalized due to a significantly
higher level of construction expenditures related to the
Company’s renewal program and other projects. Total
capital expenditures rose by more than $4.7 million over
the prior year. The remaining increase of $188,000 relates
to a variety of areas including additional facility and
equipment maintenance and support costs, higher utility
expenses and increased administrative costs related to
the Company’s operations.
general taxes -
General taxes increased $79,640, or 5%, primarily due to
higher property taxes associated with increases in utility
property and greater payroll taxes related to increased
operations staffing.
depreciation -
Depreciation expense increased by $237,956, or 5%,
corresponding to the increase in utility plant investment
partially offset by lower depreciation rates.
other expense –
Other expense, net, increased by $146,770 primarily due
to the absence of interest income related to the ANGD
note which was paid off in fiscal 2013 combined with a
greater level of corporate charitable giving and increased
SCC pipeline assessments.
interest expense –
Total interest expense remained virtually unchanged from
last year as the Company benefited in September from
lower interest expense due to its debt refinancing which
offset the increased interest incurred under the line-
of-credit.
income taxes –
Income tax expense increased by $294,753 on higher
pre-tax earnings. The effective tax rate for fiscal 2014 was
38.4% compared to 38.3% for 2013.
net income and dividends –
Net income for fiscal 2014 was $4,708,440 compared to
$4,262,052 for fiscal 2013. Basic and diluted earnings
per share were $1.00 in fiscal 2014 compared to $0.91
in fiscal 2013. Dividends declared per share of common
stock were $0.74 in fiscal 2014 compared to $1.72 in
fiscal 2013, which included the one-time special dividend
of $1.00.
1 7
ANNUAL REPORT 2014
Fiscal year 2013 compared with Fiscal year 2012
The table below reflects operating revenues, volume activity and heating degree-days.
operating revenues
YE AR ENDING SEPTEMBER 30
2013
2012
increase
percentage
Gas Utilities
Other
$ 62,024,174
$ 57,657,940
$ 4,366,234
1,181,492
1,141,747
39,745
Total Operating Revenues
$ 63,205,666
$ 58,799,687
$ 4,405,979
8%
3%
7%
delivered volumes
Year Ended September 30,
2013
2012
increase / (decrease)
percentage
Regulated Natural Gas (DTH)
Residential and Commercial
Transportation and Interruptible
6,498,783
2,910,111
5,335,836
2,981,660
1,162,947
(71,549)
Total Delivered Volumes
9,408,894
8,317,496
1,091,398
Heating Degree Days (Unofficial)
4,001
3,189
812
22%
-2%
13%
25%
Total gas utility operating revenues for the year ended
September 30, 2013 increased by 7% from the year ended
September 30, 2012. The increase in gas revenues was
primarily attributable to a 22% increase in residential and
commercial delivered volumes, partially offset by lower
natural gas commodity prices during the winter heating
season. The increase in delivered volumes was driven
by the much colder winter heating season compared to
fiscal 2012, evidenced by the 25% increase in heating
degree days. Although the total heating degree days
increased significantly, the fiscal 2013 year weather was
nearly equal to the 30-year average. Transportation and
interruptible volumes declined by 2%. Other revenues
increased by 3% due to the completion of a one-time
project more than offsetting declines in the level of
certain other contract services.
1 8
RGC RESOURCES, INC. gross margin
YE AR ENDING SEPTEMBER 30
2013
2012
increase / (decrease)
percentage
Gas Utility
Other
$ 27,108,112
$ 26,379,767
$ 728,345
494,779
553,330
(58,551)
3%
-11%
Total Gross Margin
$ 27,602,891
$ 26,933,097
$ 669,794
2%
Regulated natural gas margins from utility operations
increased by 3% from fiscal 2012 primarily as a result
of significantly higher residential and commercial sales
volumes, the implementation of a non-gas rate increase
and the addition of the SAVE Plan rider. Residential
and commercial volumes increased due to the much
colder winter season. The higher margins generated
by the increased residential and commercial volume
were mostly offset by the $1,747,000 in WNA revenues
recorded in fiscal 2012. The Company also implemented
a non-gas rate increase effective November 1, 2012 and
a SAVE Plan Rider beginning January 1, 2013. The non-
gas rate increase was designed to provide approximately
$650,000 in additional non-gas revenues annually. The
implementation of the increased rates in November
accounted for approximately $254,000 of the increase in
customer base charges and $328,000 of the additional
volumetric revenue. The SAVE Plan Rider provided
$169,000 in margin. Carrying cost revenues continued to
decline with a $299,000 reduction due to lower average
price of gas in storage during the fiscal 2013 year.
Other margins, consisting of non-utility related services,
decreased by $58,551 due to a reduction in the level of
services. Some of these non-utility services are subject to
annual or semi-annual contract renewals and the level of
activity under these contracts will fluctuate.
The changes in the components of the gas utility margin
are summarized below:
net utility margin increase
Customer Base Charge
$
279,872
Volumetric
SAVE Plan
WNA
Carrying Cost
Other
Total
2,343,618
168,747
(1,747,150)
(299,029)
(17,713)
$
728,345
1 9
ANNUAL REPORT 2014
interest expense –
Total interest expense remained virtually unchanged from
fiscal 2012 as the Company only briefly accessed its line-
of-credit during fiscal 2013.
income taxes –
Income tax expense was nearly unchanged on slightly
less pre-tax earnings. The effective tax rate for fiscal 2013
was 38.3% compared to 38.0% for 2012.
net income and dividends –
Net income for fiscal 2013 was $4,262,052 compared to
$4,296,745 for fiscal 2012. Basic and diluted earnings
per share were $0.91 in fiscal 2013 compared to $0.92
in fiscal 2012. Dividends declared per share of common
stock were $1.72 in fiscal 2013, which includes the one-
time special dividend of $1.00 paid in December 2012,
compared to $0.70 in fiscal 2012.
Asset Management
Roanoke Gas uses a third-party asset manager to
manage its pipeline transportation, storage rights and
gas supply inventories and deliveries. In return for being
able to utilize the excess capacities of the transportation
and storage rights, the third party pays Roanoke Gas a
monthly utilization fee, which is used to reduce the cost
of gas for customers. Under the provision of the asset
management contract, the Company has an obligation
to purchase its winter storage requirements during
the spring and summer injection periods at the market
price in place at the time of purchase. This commitment
amounts to approximately 2,071,000 decatherms per
year or approximately one-third of the Company’s total
annual purchases. In addition to the storage purchase
requirements, the Company generally purchases its
monthly supply requirements from the asset manager
based on market price.
operations and maintenance expense –
Operations and maintenance expenses increased by
$305,906, or 2%, in fiscal 2013 compared with fiscal 2012
primarily due to higher labor costs, contracted services,
bad debt expense, corporate insurance expense and stock
option expense more than offsetting greater capitalization
of Company overheads on construction projects and
LNG (liquefied natural gas) production. Labor costs and
contracted services increased by $453,000 primarily
due to an increase in operations staffing, timing of leak
surveys and pipeline right-of-way clearing, costs related
to an SCC mandated meter installation inspection and
remediation program, and network services support and
training. Bad debt expense increased by approximately
$74,000. Total bad debt expense was 0.13% of gross
natural gas billings for fiscal 2013 and is consistent with
the five-year average. Fiscal 2012’s bad debt expense
ratio was only 0.02%. This unusually low rate was due to
much warmer weather and low gas prices, resulting in
the lowest bad debt write-off in over twenty-five years.
Corporate property and liability insurance increased
by $126,000 due to a combination of higher premiums
and increased general liability coverage limits. The
Company also recognized $85,000 in expense related to
the granting of stock options. These were the first option
grants since 2002. These higher costs were partially
offset by greater capitalization of overheads due to a
higher level of pipeline construction expenditures and
increased LNG production. The Company continued to
increase activity under its pipeline renewal program,
with total capital expenditures rising by more than
$1.3 million over fiscal 2012, resulting in a greater
capitalization of overheads.
general taxes -
General taxes increased $114,066, or 8%, primarily due
to higher property taxes associated with increases in
utility property.
depreciation -
Depreciation expense increased by $241,302, or 6%,
corresponding to the increase in utility plant investment.
other income (expense) –
Other expense, net, increased by $40,161 primarily due
to the reduction in interest income related to the payoff of
the ANGD note in fiscal 2013.
2 0
RGC RESOURCES, INC.
Capital Resources and
Liquidity
operating cash flows, line-of-credit agreement, long-term
debt, and to a lesser extent, capital raised through the
Company’s stock plans.
Due to the capital intensive nature of the utility business,
as well as the related weather sensitivity, the Company’s
primary capital needs are for the funding of its continuing
construction program, the seasonal funding of its natural
gas inventories and accounts receivables and payment of
dividends. To meet these needs, the Company relies on its
Cash and cash equivalents decreased by $1,996,467 in
fiscal 2014 compared to a decrease of $6,063,647 in fiscal
2013 and an increase of $958,442 in fiscal 2012. The
following table summarizes the categories of sources and
uses of cash:
cash Flow summary
YE AR ENDING SEPTEMBER 30
Provided by operating activities
Used in investing activities
Provided by (used in) financing activities
5,862,365
(6,153,207)
2014
2013
2012
$ 6,839,738
$ 10,037,070
$ 11,783,041
(14,698,570)
(9,947,510)
(8,650,715)
(2,173,884)
Increase (decrease) in cash and cash equivalents
$ (1,996,467)
$ (6,063,647)
$ 958,442
As discussed below, the Company increased its capital
spending in fiscal 2014 and financed the increase through
operating cash flow and utilization of the line-of-credit.
cash Flows From operating activities:
The seasonal nature of the natural gas business causes
operating cash flows to fluctuate significantly during
the year as well as from year to year. Factors, including
weather, energy prices, natural gas storage levels and
customer collections, all contribute to working capital
levels and related cash flows. Generally, operating cash
flows are positive during the second and third quarters as
a combination of earnings, declining storage gas levels
and collections on customer accounts all contribute to
higher cash levels. During the first and fourth quarters,
operating cash flows generally decrease due to the
combination of increases in natural gas storage levels
and rising customer receivable balances.
is allowed to recover the actual cost of natural gas from
its customers. Any amounts billed in excess of the actual
cost are considered an over-recovery of these costs and
are reflected as a liability on the financial statements.
Conversely, any actual costs incurred in excess of
amounts billed are considered an under-recovery of
gas costs and are reflected as an asset on the financial
statements. During fiscal 2014, the Company went from
an over-recovered position of $1,027,000 to an under-
recovered position of $181,000, which used $1,208,000
in operating cash. Conversely, during fiscal 2013, the
Company went from an under-recovered position of
$687,000 to an over-recovered position of $1,027,000,
which generated $1,714,000 in operating cash. Increases
in operating cash flows due to greater contributions
from net income and depreciation offset the impact
of increased investment in gas in storage and other
operating variances.
Cash provided by operating activities was $6,840,000 in
fiscal 2014, $10,037,000 in fiscal 2013 and $11,783,000 in
fiscal 2012. Cash provided by operating activities declined
by approximately $3,197,000 from last year primarily
as a result of a significant move from an over-recovery
of gas costs to an under-recovery position during fiscal
2014. As provided under the provisions of the Company’s
Purchased Gas Adjustment (“PGA”) clause, the Company
Cash provided by operating activities decreased for fiscal
2013 from fiscal 2012 by $1,746,000 due to an increase in
cost of gas in storage partially offset by an over-recovery
on gas costs and the tax deferral benefits of bonus
depreciation. The cost of gas in storage had declined for
the last few years as the commodity price of gas declined;
however, when the Company began its fiscal 2013
summer storage program to refill the storage balances,
2 1
ANNUAL REPORT 2014 the commodity price of gas was higher than fiscal 2012
resulting in higher storage balances by year-end. The
average price of natural gas in storage was $4.08 and
$3.51 as of September 30, 2013 and 2012, respectively.
During fiscal 2013, the Company had a $1,714,000
operating source of cash as the Company went from an
under-recovered position to an over-recovered position.
During fiscal 2012, the Company had an operating use of
cash of $1,043,000 as the Company went from an over-
recovered position to an under-recovered position. In
addition, 50% bonus depreciation for tax purposes was in
place for fiscal 2013 resulting in the Company’s deferred
income tax liability associated with its utility property
increasing by $1,700,000 in fiscal 2013 and more than
$2,200,000 in fiscal 2012, thereby deferring payment
of income taxes until future periods. The deferred tax
liability related to utility property increased by less than
$500,000 in fiscal 2014 as bonus depreciation expired
December 31, 2013. The Company has approximately
$17,100,000 in deferred tax liabilities related to
accelerated and bonus depreciation at September 30,
2014 on its utility plant that will begin to reverse in 2015
or later resulting in additional cash outflows for payment
of the deferred taxes.
TOTAL long-term
CAPITALIZATION
(In Millions)
82.5
76.8
74.3
63.7
62.5
10
11
12
13
14
90
80
70
60
50
2 2
cash Flows used in investing activities:
Investing activities are generally composed of
expenditures under the Company’s construction
program, which involves a combination of replacing
aging bare steel and cast iron pipe with new plastic or
coated steel pipe, making improvements to the LNG
plant and expansion of its natural gas system to meet
the demands of customer growth. The Company’s
expenditures related to its pipeline renewal program
and other system and infrastructure improvements
and expansion have continued to trend upward with
more than $14,700,000 spent in fiscal 2014 compared to
approximately $10,000,000 in fiscal 2013 and $8,700,000
in fiscal 2012. The Company renewed 13.6 miles of bare
steel and cast iron natural gas distribution main and
replaced 942 services in fiscal 2014. This compares to
13 miles main and 1,064 services in fiscal 2013 and 15.8
miles of main and 1,429 services in fiscal 2012. Total
costs related to the renewal program are higher this year
even though the total miles of mains were slightly higher
and the number of services replaced were less than last
year. As the renewal program has progressed, most of
the less complex and more highly concentrated areas
of the Company’s natural gas distribution system have
been completed leaving the more difficult and smaller
sections to be done. Completion of the remaining pipeline
replacement will more than likely be at a higher per foot
cost. The Company’s capital expenditures also included
costs to extend mains and services to 673 new customers
in fiscal 2014 compared to 468 in fiscal 2013 and 450
in fiscal 2012. In addition, the Company completed
the replacement of its Gala transfer station and made
significant progress in the replacement of the boil off
compressor at the LNG plant.
RGC Resources is committed to the safe and reliable
delivery of natural gas to its customers and, as a result,
plans to commit the necessary resources to its pipeline
renewal program with an expectation to replace all
remaining cast iron and bare steel pipe within the
next three years. As a reflection of this commitment,
the Company’s capital budget for next year currently
is estimated to be near the fiscal 2014 level as work
continues on the pipeline replacement program and the
installation of a new boil off compressor at the LNG plant
is completed. Depreciation provided approximately 33% of
the current year’s capital expenditures compared to 47%
for 2013 and 51% for 2012. Upon completion of the bare
steel and cast iron pipe replacement, the Company plans
RGC RESOURCES, INC. to direct its efforts to replacing all pre-1973 plastic mains
with current polyethylene pipe. This project encompasses
approximately 40 miles of natural gas main with a 2019
anticipated completion. With future capital expenditures
projected to remain at higher than historical levels over
these next few years, the Company expects to increase its
borrowing activity.
to the Company under the DRIP Plan. The Company’s
consolidated capitalization was 63.0% equity and 37.0%
long-term debt at September 30, 2014. This compares to
63.9% equity and 36.1% debt, including the note payable,
at September 30, 2013. Including the line-of-credit as
part of total consolidated capitalization, September 30,
2014 ratios would be 56.8% equity and 43.2% debt.
cash Flows provided by (used in)
Financing activities:
Financing activities generally consist of long-term and
short-term borrowings and repayments, issuance of stock
and the payment of dividends. As mentioned above, the
Company uses its line-of-credit arrangement to fund
seasonal working capital and provide temporary financing
for capital projects. Cash flows provided by financing
activities were $5,862,000 for fiscal 2014 compared to
cash flows used in financing activities of $6,153,000 for
fiscal 2013 and $2,174,000 for fiscal 2012. The Company
experienced significant activity in financing cash flows
in 2014. The Company refinanced $28,000,000 of its
debt, including $2,238,000 in early termination fees on
the notes and corresponding interest rate swaps, with
$30,500,000 in unsecured 20-year term notes. The early
termination fees have been deferred as a regulatory asset
and will be amortized over the term of the new notes
as a component of interest expense. The $28,000,000 in
retired debt had an average interest rate of 6.30% with
an effective rate of 6.43%. The new debt has a stated
interest rate of 4.26% and an effective rate of 4.67%. The
Company will realize approximately $376,000 in lower
annual interest expense as a result of the refinancing.
The Company also increased the utilization of its line-
of-credit to fund both the Company’s seasonal working
capital needs as well as bridge financing for its capital
budget. At the current level of capital expenditures,
operating cash flows are not sufficient to meet both the
capital expenditure requirements and the payment of
dividends. Dividends returned to normal levels in fiscal
2014 at an annual rate of $0.74 per share. Last year
included a special $1.00 per share dividend paid by the
Company on December 17, 2012. The special dividend
totaled $4,675,337, of which $425,630 was returned
The remaining difference in financing activities related to
the receipt of the pay-off of the balance on the two notes
in fiscal 2013 offset by an increase in the regular annual
dividend payment rate from $0.72 per share to $0.74
per share.
On March 31, 2014, the Company entered into a new line-
of-credit agreement. This new agreement maintains the
same terms and rates as provided for under the expired
agreement with an increase in the total borrowing limit.
The interest rate is based on 30-day LIBOR plus 100
basis points and includes an availability fee of 15 basis
points applied to the difference between the face amount
of the note and the average outstanding balance during
the period. The Company maintained the multi-tiered
borrowing limits to accommodate seasonal borrowing
demands and minimize overall borrowing costs, with
available limits ranging from $1,000,000 to $19,000,000
during the term of the agreement. The upper limit of the
line-of-credit increased over prior years due to expected
capital expenditure funding needs. The line-of-credit
agreement will expire March 31, 2015, unless extended.
The Company anticipates being able to extend or replace
the line-of-credit upon expiration; however, there is no
guarantee that the line-of-credit will be extended or
replaced under the same or equivalent terms currently
in place.
Off-Balance Sheet
Arrangements
The Company has no off-balance sheet arrangements as
defined in Regulation S-K, Item 303(a)(4)(ii).
2 3
ANNUAL REPORT 2014 Contractual Obligations and Commitments
The Company has incurred various contractual obligations and commitments in the normal course of business. As of
September 30, 2014, the estimated recorded and unrecorded obligations are as follows:
less than
1 year
1-3 years
4-5 years
after 5 years
total
recorded CONTR ACTUAL
OBLIGATIONS:
Long-Term Debt (1)
Short-Term Debt (2)
$ — $ —
$ —
$ 30,500,000
$ 30,500,000
9,045,050
—
—
—
9,045,050
Total
$ 9,045,050
$ — $ —
$ 30,500,000
$ 39,545,050
(1) See Note 4 to the consolidated financial statements.
(2) See Note 3 to the consolidated financial statements.
less than
1 year
1-3 years
4-5 years
after 5 years
total
unrecorded CONTRACTUAL
OBLIGATIONS, NOT REFLECTED
IN CONSOLIDATED BALANCE
SHEET IN ACCORDANCE WITH
U.S. GAAP:
Pipeline and Storage Capacity (3)
$ 11,383,418
$ 21,330,892 $ 13,903,581
$ 2,411,198
$ 49,029,089
Gas Supply (4)
Interest on Short-Term Debt (5)
—
19,884
—
—
—
—
—
—
—
19,884
Interest on Long-Term Debt (6)
913,119
2,598,600
2,598,600
19,875,681
25,986,000
Pension Plan Funding (7)
Other Obligations (8)
—
—
—
—
—
89,828
110,750
19,339
26,880
246,797
Total
$ 12,406,249
$ 24,040,242 $ 16,521,520
$ 22,313,759
$ 75,281,770
(3) Recoverable through the PGA process.
(4) Volumetric obligation for the purchase of contracted decatherms of natural gas at market prices in effect at
the time of purchase. See Note 9 to the consolidated financial statements.
(5) Accrued interest on line-of-credit balance at September 30, 2014 including minimum facility fee on unused
line-of-credit. See Note 3 to the consolidated financial statements.
(6) See Note 4 to the consolidated financial statements.
(7) Estimated minimum funding requirements beyond five years is not available. See Note 6 to the consolidated
financial statements.
(8) Various lease, maintenance, equipment and service contracts.
2 4
RGC RESOURCES, INC. Regulatory Affairs
On November 1, 2013, the Company placed into effect
new base rates, subject to refund, that would provide
approximately $1,664,000 in additional annual non-gas
revenues. On March 17, 2014, the Company reached
a stipulated agreement with the SCC staff that would
provide $887,062 in annual non-gas revenues. A hearing
was held on March 25, 2014 resulting in the approval of
the stipulated agreement. The stipulation provided for
a 9.75% authorized return on equity as was previously
in place; however, this was below the 10.1% requested
by the Company in the rate filing. On May 9, 2014, the
SCC issued its final order approving the increase in
annual non-gas revenues agreed to in the stipulation.
The Company completed its refund of revenues collected
in excess of the approved rates plus interest to its
customers in the Company’s fiscal third quarter.
In connection with the order approving the non-gas rate
award, the SCC also approved a change to the Company’s
WNA mechanism. Previously, the WNA provided for
a weather band of 3% above or below the 30-year
temperature average whereby the Company would
recover from its customers the lost margin (excluding
gas costs) from the impact of weather that was more
than 3% warmer than the 30-year average or refund to
customers the excess earned from weather that is more
than 3% colder than the 30-year average. The WNA is
an important regulatory feature for the Company. As the
Company’s non-gas rates are established and approved
by the SCC based on the 30-year average temperatures,
weather that is warmer than the 30-year average will
result in the Company earning less than what they are
allowed under the rates, while weather that is colder than
the 30-year average will result in the Company earning at
a level above what the rates were designed. The weather
band reduced the volatility in earnings due to weather
by limiting both the upside and the downside to a 3%
swing in weather. During the WNA year ended March
31, 2014, the number of heating degree days were more
than 10% colder than the 30-year average. As a result,
the Company refunded to customers $707,000 in margin
for the additional sales resulting from weather that was
between 3% and 10% colder than the 30-year average.
The Company was able to keep the additional margin
earned on weather up to the 3% weather band.
Effective with the WNA period that began April 1, 2014,
the SCC removed the 3% weather band. The WNA will
now result in either a recovery or refund of revenues
due to any variation from the 30-year average. Although
the model to calculate and adjust for the impact of the
deviation from the 30-year average has some limitations,
it provides the Company with a more predictable utility
operating margin that better aligns with the authorized
return as provided for in the Company’s utility billing
rates. As of September 30, 2014, the Company accrued
$144,000 in WNA revenues attributable to weather that
had 58 fewer heating degree days than the 30-year
average during the first six months of the new WNA period.
On June 4, 2014, the Company filed an application with
the SCC requesting approval to extend its authority to
incur short-term indebtedness of up to $30,000,000 and
to issue up to $60,000,000 in long-term debt securities as
part of its long-term financing plan, which included the
refinancing of higher interest rate debt and funding for
the Company’s pipeline replacement program and other
infrastructure projects. On June 25, 2014, the SCC issued
an order granting the approval of the Company’s request.
On June 30, 2014, the Company filed an application for
modification of the SAVE (Steps to Advance Virginia’s
Energy) Plan and Rider. The original SAVE Plan and Rider
were approved by the SCC through an order issued on
August 29, 2012 and was amended on August 16, 2013.
The original SAVE Plan was designed to facilitate the
accelerated replacement of the remaining bare steel
and cast iron natural gas pipe by providing a mechanism
for the Company to recover the related depreciation and
expenses and return on rate base of the additional capital
investment without the filing of a formal application for an
increase in non-gas base rates. With the amendment, the
Company added two unique projects; the replacement of
the boil-off compressor at the Company’s LNG plant and
replacement of the natural gas transfer station located
in Gala, VA. The Plan was amended again in June 2014
to increase the expected investment for the continued
replacement of the Company’s natural gas distribution
pipe and added the investment for the related meter and
regulator installations located on customer premises
for the 2015 SAVE Plan year. All of these projects
included under the SAVE Plan will enhance the safety
and reliability of the Company’s gas distribution system.
In addition, the recovery of the depreciation and related
expenses on these projects through the SAVE Plan rider
will allow the Company to forego a formal non-gas rate
increase at this time.
2 5
ANNUAL REPORT 2014 The Company’s provision for depreciation is computed
principally based on composite rates determined by
depreciation studies. These depreciation studies are
required to be performed on the regulated utility assets
of Roanoke Gas Company at least every five years. In
June 2014, the Company filed an updated depreciation
study with the SCC to update the previous study that was
implemented in fiscal 2009. The SCC approved new rates
in September 2014 which resulted in a small reduction
in the overall composite depreciation rate from 3.35% to
3.25%. The new rates were implemented retroactive to
October 1, 2013.
In 2013, the SCC issued new inspection protocols
requiring all meter installations to be inspected once
every three years, on a continuous cycle. The Company
has implemented the program and the inspection and
remediation program is ongoing.
Critical Accounting
Policies and Estimates
The consolidated financial statements of Resources
are prepared in accordance with accounting principles
generally accepted in the United States of America. The
amounts of assets, liabilities, revenues and expenses
reported in the Company’s financial statements
are affected by accounting policies, estimates and
assumptions that are necessary to comply with generally
accepted accounting principles. Estimates used in the
financial statements are derived from prior experience,
statistical analysis and professional judgments. Actual
results may differ significantly from these estimates and
assumptions.
The Company considers an estimate to be critical if it
is material to the financial statements and requires
assumptions to be made that were uncertain at the time
the estimate was made and changes in the estimate are
reasonably likely to occur from period to period. The
Company considers the following accounting policies and
estimates to be critical.
costs that have been or are expected to be recovered
from customers in a period different from the period
in which the costs would be charged to expense by an
unregulated enterprise. When this occurs, costs are
deferred as assets in the consolidated balance sheet
(regulatory assets) and recorded as expenses when such
amounts are reflected in rates. Additionally, regulators
can impose liabilities upon a regulated company for
amounts previously collected from customers and for
current collection in rates of costs that are expected to be
incurred in the future (regulatory liabilities).
If, for any reason, the Company ceases to meet the
criteria for application of regulatory accounting treatment
for all or part of its operations, the Company would
remove the applicable regulatory assets or liabilities from
the balance sheet and include them in the consolidated
statements of income and comprehensive income for the
period in which the discontinuance occurred.
revenue recognition –
Regulated utility sales and transportation revenues are
based upon rates approved by the SCC. The non-gas
cost component of rates may not be changed without a
formal rate application and corresponding authorization
by the SCC in the form of a Commission order; however,
the gas cost component of rates may be adjusted
quarterly through the purchased gas adjustment (“PGA”)
mechanism with administrative approval from the SCC.
When the Company files a request for a non-gas rate
increase, the SCC may allow the Company to place such
rates into effect subject to refund pending a final order.
Under these circumstances, the Company estimates
the amount of increase it anticipates will be approved
based on the best available information. The Company
also bills customers through a SAVE Rider that provides
a mechanism to recover on a prospective basis the costs
associated with the Company’s expected investment
related to the replacement of natural gas distribution
pipe and other qualifying projects. As required under the
provisions of FASB ASC No. 980, “Regulated Operations,”
the Company recognizes billed revenue related to the
SAVE projects to the extent such revenues have been
earned under the provisions of the SAVE Plan.
regulatory accounting –
The Company’s regulated operations follow the
accounting and reporting requirements of FASB ASC No.
980, “Regulated Operations.” The economic effects of
regulation can result in a regulated company deferring
The Company bills its regulated natural gas customers
on a monthly cycle. The billing cycle for most customers
does not coincide with the accounting periods used for
financial reporting. The Company accrues estimated
revenue for natural gas delivered to customers but
2 6
RGC RESOURCES, INC. not yet billed during the accounting period based on
weather during the period and current and historical
data. The financial statements include unbilled revenue of
$1,071,128 and $1,056,253 as of September 30, 2014 and
2013, respectively.
allowance For doubtFul accounts –
The Company evaluates the collectability of its accounts
receivable balances based upon a variety of factors
including loss history, level of delinquent account
balances, collections on previously written off accounts
and general economic climate.
pension and postretirement beneFits –
The Company offers a defined benefit pension plan
(“pension plan”) and a postretirement medical and
life insurance plan (“postretirement plan”) to eligible
employees. The expenses and liabilities associated with
these plans, as disclosed in Note 6 to the consolidated
financial statements, are based on numerous
assumptions and factors, including provisions of the
plans, employee demographics, contributions made to
the plan, return on plan assets and various actuarial
calculations, assumptions and accounting requirements.
In regard to the pension plan, specific factors include
assumptions regarding the discount rate used in
average shares
outstanding
(In Millions)
4.75
4.72
4.70
4.65
4.59
4.51
4.50
4.25
4.00
10
11
12
13
14
determining future benefit obligations, expected long-
term rate of return on plan assets, compensation
increases and life expectancies. Similarly, the
postretirement medical plan also requires the estimation
of many of the same factors as the pension plan in
addition to assumptions regarding the rate of medical
inflation and Medicare availability. Actual results may
differ materially from the results expected from the
actuarial assumptions due to changing economic
conditions, differences in actual returns on plan assets,
different rates of medical inflation, volatility in interest
rates and changes in life expectancy. Such differences
may result in a material impact on the amount of expense
recorded in future periods or the value of the obligations
on the balance sheet.
In selecting the discount rate to be used in determining
the benefit liability, the Company utilized the Citigroup
yield curves which incorporate the rates of return on
high-quality, fixed-income investments that corresponded
to the length and timing of benefit streams expected
under both the pension plan and postretirement plan. The
Company used a discount rate of 4.22% and 4.10% for
valuing its pension plan liability and postretirement plan
liability at September 30, 2014, representing a decrease of
0.60% and 0.63% in their respective rates from the prior
year. The decrease in the discount rates corresponded
with similar decreases in long-term interest rates. The
30-year Treasury rate decreased from 3.69% to 3.21%.
Likewise, the Moody’s Aaa and Moody’s Baa decreased by
0.51% and 0.58%, respectively. The decrease in discount
rates for valuing the benefit liabilities nearly reversed
the increase in rates experienced in the prior fiscal year.
The pension and postretirement plan liability discount
rates increased by 0.76% and 0.78% for the September
30, 2013 valuation from those used for the September
30, 2012 valuation. The decrease in the discount rates for
both plans resulted in a significant increase in the benefit
obligation at September 30, 2014. Both plans experienced
better than expected returns on the related pension
and postretirement assets, which partially offset the
deterioration in the funded status of both plans due to the
reduction in the discount rates used to value both plans’
liabilities. As a result of the larger funded deficit, pension
and postretirement medical plan expense will increase
in fiscal 2015 due to an increase in the amortization of
the actuarial loss due to the reduction in the discount
rate and an increase in life expectancy assumptions as
discussed below. The following tables reflect the funded
status of both plans at the corresponding fiscal year ends.
2 7
ANNUAL REPORT 2014 Funded status - september 30, 2014
Benefit obligation
Fair value of assets
pension
postretirement
total
$ 24,636,695
$ 14,983,169
$ 39,619,864
20,514,179
10,646,249
31,160,428
Funded status
$ (4,122,516)
$ (4,336,920)
$ (8,459,436)
Funded status - september 30, 2013
Benefit obligation
Fair value of assets
pension
postretirement
total
$ 21,468,769
$ 13,028,628
$ 34,497,397
18,801,262
10,114,062
28,915,324
Funded status
$ (2,667,507)
$ (2,914,566)
$ (5,582,073)
The current economic environment makes it difficult to
project interest rates and future investment returns. If
the economy improves, long-term interest rates could
increase, reducing the benefit liabilities and increasing
the investment returns. However, if the economy
stagnates or declines, interest rates could remain at
these lower levels or even drop, leading to an increase
in the benefit liabilities and potential reduction in
investment returns. The Company also annually evaluates
the returns on its targeted investment allocation model.
The investment policy as of the measurement date in
September reflected a targeted allocation of 60% equity
and 40% fixed income on the pension plan and a targeted
allocation of 50% equity and 50% fixed income for the
postretirement plan. As a result of this evaluation, the
Company set its expected annual return on pension
assets at 7.00% and postretirement assets at 4.90%
(net of income taxes) for fiscal 2015. These rates are
consistent with the expected long-term rates in place
during fiscal 2014.
In August 2014, the Highway and Transportation Funding
Act of 2014 (“HATFA”) was signed into law, which
included a provision to extend the interest rate corridors
introduced in 2012 under the Moving Ahead for Progress
in the 21st Century Act (“MAP-21”). MAP-21 provided
temporary funding relief for defined benefit pension
plans. The requirements of the Employee Retirement
Income Security Act of 1974 (ERISA) and the Pension
Protection Act of 2006 (PPA) subject defined benefit plans
to minimum funding rules. As a result, when interest
rates are low, pension plan liabilities increase thereby
resulting in higher mandatory contributions to meet
minimum funding obligations. MAP-21 provided funding
relief by allowing pension plans to adjust the interest
rates used in determining funding requirements so that
they are within 10% of the average of interest rates for
the 25-year period preceding the current year for funding
calculations for 2013 to within 30% for funding periods
beginning in 2016. HATFA extended the period of time
that the 10% corridor instituted by MAP-21 may be used
for funding calculations. Under HATFA, the 10% corridor
extends through plan years that begin in 2017 and phases
out to a 30% corridor in 2021 and later. HATFA is expected
to significantly increase the effective interest rates used
in determining funding requirements and could result
in a deterioration of the pension plan funded status
resulting in much greater funding requirements in the
future as well as higher PBGC (Pension Benefit Guaranty
Corporation) premiums paid by sponsors of pension
plans to protect participants in the event of default by
the employer. Management estimates that under the
2 8
RGC RESOURCES, INC. provisions of HATFA, the Company may have no minimum
funding requirements over the next few years. Although
HATFA and MAP-21 allow the Company some short-
term funding relief, management expects to continue
to fund its pension plan at the greater of any minimum
pension contribution requirement or its expense level
for subsequent years. As a result, the Company expects
to contribute approximately $800,000 to its pension plan
and $500,000 to its postretirement plan in fiscal 2015. The
Company will continue to evaluate its benefit plan funding
levels in light of funding requirements and ongoing
investment returns and make adjustments, as necessary,
to avoid benefit restrictions.
On October 27, 2014, the Society of Actuaries released the
final reports of the pension plan RP-2014 Mortality Tables
and the Mortality Improvement Scale MP-2014. The new
mortality tables, which will be adopted by the Company
for its next pension valuation, extend the assumed life
expectancy of participants in defined benefit plans. The
estimated impact of the change in assumed mortality
would increase the Company’s pension liability by 6% to
8% and increase future pension expense.
The following schedule reflects the sensitivity of pension costs to changes in certain actuarial assumptions, assuming
that the other components of the calculation remain constant.
actuarial assumption
Discount rate
Rate of return on plan assets
Rate of increase in compensation
change in
assumption
-0.25%
-0.25%
0.25%
increase in
pension cost
$ 102,000
51,000
53,000
increase in projected
benefit obligation
$ 1,012,000
N/A
293,000
The following schedule reflects the sensitivity of postretirement benefit costs from changes in certain actuarial
assumptions, while the other components of the calculation remain constant.
actuarial assumption
Discount rate
Rate of return on plan assets
Health care cost trend rate
change in
assumption
-0.25%
-0.25%
0.25%
increase in
postretirement
benefit cost
$ 30,000
26,000
71,000
increase in
accumulated
postretirement
benefit obligation
$ 519,000
N/A
539,000
derivatives –
The Company may hedge certain risks incurred in its
operation through the use of derivative instruments.
The Company applies the requirements of FASB ASC
No. 815, “Derivatives and Hedging,” which requires
the recognition of derivative instruments as assets or
liabilities in the Company’s balance sheet at fair value. In
most instances, fair value is based upon quoted futures
prices for natural gas commodities and interest rate
futures for interest rate swaps. Changes in the commodity
and futures markets will impact the estimates of fair
value in the future. Furthermore, the actual market
value at the point of realization of the derivative may be
significantly different from the values used in determining
fair value in prior financial statements. The Company had
no commodity or interest rate derivatives outstanding at
September 30, 2014.
2 9
ANNUAL REPORT 2014 market price & dividend information
RGC Resources’ common stock is listed on the NASDAq
Global Market under the trading symbol RGCO. Payment
of dividends is within the discretion of the Board of
Directors and will depend on, among other factors,
earnings, capital requirements, and the operating and
financial condition of the Company. The company’s long-
term indebtedness contains restrictions on long-term
capitalization ratios.
YE AR ENDING SEPTEMBER 30
range of bid prices
low
high
cash dividends
declared
$
19.98
$
18.10
$
0.185
20.06
19.73
20.51
18.46
19.00
19.17
0.185
0.185
0.185
$
19.72
$
17.51
$
0.180
19.40
21.94
20.97
17.96
18.44
17.86
0.180
0.180
0.180
1.000
2014
First quarter
Second quarter
Third quarter
Fourth quarter
2013
First quarter
Second quarter
Third quarter
Fourth quarter
Special Dividend
3 0
RGC RESOURCES, INC. CAPITALIZATION STATISTICS
YE AR ENDING SEPTEMBER 30
2014
2013
2012
2011
2010
common stocK
Shares Issued
Earnings Per Share:
4,720,378
4,709,326
4,670,567
4,624,682
4,548,864
Basic Earnings Per Share
Diluted Earnings Per Share
Dividends Paid Per Share (Cash)
$
$
$
1.00
1.00
0.74
$
$
$
0.91
0.91
1.72
$
$
$
0.92
0.92
0.70
$
$
$
1.01
1.01
0.68
$
$
$
0.98
0.98
0.66
Dividends Paid Out Ratio
74.0%
189.0%
76.1%
67.3%
67.3%
capitaliZation ratios
Long-Term Debt,
Including Current Maturities
Common Stock And Surplus
37.0%
63.0%
20.8%
79.2%
20.4%
79.6%
36.5%
63.5%
37.7%
62.3%
Total
100.0%
100.0%
100.0%
100.0%
100.0%
Long-Term Debt,
Including Current Maturities
$
30,500,000
$
13,000,000
$
13,000,000
$
28,000,000
$
28,000,000
Common Stock And Surplus
$
52,020,847
$
49,502,422
$
50,682,930
$
48,785,778
$
46,309,747
Total Capitalization Plus
Current Maturities
$
82,520,847
$
62,502,422
$
63,682,930
$
76,785,778
$
74,309,747
3 1
ANNUAL REPORT 2014
summary of gas sales & statistics
YE AR ENDING SEPTEMBER 30
2014
2013
2012
2011
2010
revenues:
Residential Sales
Commercial Sales
Interruptible Sales
$ 42,668,037 $ 36,271,831 $ 32,784,791 $ 40,051,923 $ 42,277,903
25,323,023
20,597,084
19,164,789
23,463,529
25,166,672
1,726,749
1,205,788
1,397,353
1,572,270
573,946
Transportation Gas Sales
3,157,691
2,912,550
2,957,344
2,843,115
2,674,151
Inventory Carrying Cost Revenues
879,381
937,684
1,236,713
1,395,877
1,546,544
Late Payment Charges
Miscellaneous Gas Utility Revenue
43,451
67,155
37,407
61,830
37,519
79,431
44,252
63,949
112,654
123,493
Other
Total
net income
dth delivered:
Residential
Commercial
Interruptible
1,150,647
1,181,492
1,141,747
1,315,251
1,397,256
$ 75,016,134 $ 63,205,666 $ 58,799,687 $ 70,798,871 $ 73,823,914
$ 4,708,440 $ 4,262,052 $ 4,296,745 $ 4,653,473 $ 4,445,436
4,073,831
3,821,200
3,036,076
3,866,489
3,910,639
2,932,089
2,677,583
2,299,760
2,715,998
2,712,692
305,212
247,069
286,326
263,851
79,858
Transportation Gas
2,776,519
2,663,042
2,695,334
2,698,260
2,610,962
Total
10,087,651
9,408,894
8,317,496
9,544,598
9,314,151
heating degree days
4,351
4,001
3,189
4,091
4,047
number o F customers:
Natural Gas
Residential
Commercial
Interruptible and Interruptible
53,410
5,108
53,093
5,110
52,836
5,072
52,579
5,073
51,922
5,020
Transportation Service
35
35
33
32
33
Total
58,553
58,238
57,941
57,684
56,975
gas account ( dth):
Natural Gas Available
10,213,316
9,622,988
8,521,983
9,772,756
9,561,029
Natural Gas Deliveries
10,087,651
9,408,894
8,317,496
9,544,598
9,314,151
Storage - LNG
137,352
139,875
111,735
114,670
136,972
Company Use And Miscellaneous
System Loss
Total Gas Available
44,486
(56,173)
50,282
23,937
41,620
51,132
42,147
71,341
47,759
62,147
10,213,316
9,622,988
8,521,983
9,772,756
9,561,029
total assets
$139,320,722 $124,526,701 $129,756,338 $125,549,049 $120,683,316
long-term obligations
$ 30,500,000 $ 13,000,000 $ 13,000,000 $ 13,000,000 $ 28,000,000
3 2
RGC RESOURCES, INC. CORPORATE INFORMATION
CORPORATE OFFICE
rgC resources, Inc.
519 Kimball avenue, n.E.
P.O. Box 13007
roanoke, va 24030
tel: (540) 777-4gaS (4427)
fax: (540) 777-2636
INDEPENDENT REGISTERED ACCOUNTING
FIRM
Brown Edwards & Company, l.l.P.
1715 Pratt Drive, Suite 2700
Blacksburg, va 24060
COMMON STOCK TRANSFER AGENT,
REGISTRAR, DIVIDEND DISBURSING
american Stock transfer & trust Company, llC
6201 15th avenue
Brooklyn, ny 11219
(866) 673-8053
COMMON STOCK
RGC Resources’ common stock is listed on the NASDAQ
Global Market under the trading symbol rgCO.
DIRECT DEPOSIT OF DIVIDENDS AND
SAFEKEEPING OF STOCK CERTIFICATES
Shareholders can have their cash dividends deposited
automatically into checking, savings or money market
accounts. The shareholder’s financial institution must
be a member of the Automated Clearing House. Also,
RGC Resources offers safekeeping of stock certificates
for shares enrolled in the dividend reinvestment plan.
For more information about these shareholder services,
please contact the Transfer Agent, American Stock
Transfer & Trust Company, LLC.
10-K REPORT
A copy of RGC Resources, Inc.’s latest annual report
to the Securities & Exchange Commission on Form
10-K will be provided without charge upon written
request to:
Dale P. lee
vice President and Secretary
rgC resources, Inc.
P.O. Box 13007
roanoke, va 24030
(540) 777-3846
Access all of RGC Resources Inc.’s Securities and
Exchange filings through the links provided on our
website at www.rgcresources.com.
SHAREHOLDER INQUIRIES
Questions concerning shareholder accounts, stock
transfer requirements, consolidation of accounts,
lost stock certificates, replacement of lost dividend
checks, payment of dividends, direct deposit of
dividends, initial cash payments, optional cash
payments and name or address changes should
be directed to the Transfer Agent, American
Stock Transfer & Trust Company, LLC. All other
shareholder questions should be directed to:
rgC resources, Inc.
vice President and Secretary
P.O. Box 13007
roanoke, va 24030
(540) 777-3846
FINANCIAL INQUIRIES
All financial analysts and professional investment
managers should direct their questions and
requests for more financial information to:
rgC resources, Inc.
vice President and Secretary
P.O. Box 13007
roanoke, va 24030
(540) 777-3846
Access up-to-date information on RGC Resources
and its subsidiaries at www.rgcresources.com.
Photography by Amy Nance-Pearman at boydphotography.com
519 Kimball Avenue, N.E.
P.O. Box 13007
Roanoke, Virginia 24030
www.rgcresources.com
Trading on NASDAQ as RGCO