ITEM 2 – MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
This report contains forward-looking statements that relate to future transactions, events or expectations. In addition, Resources 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 other 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” in the Company’s 2018 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.
The three-month and six-month earnings presented herein should not be considered as reflective of the Company’s consolidated financial results for the fiscal year ending September 30, 2019. The total revenues and margins realized during the first six months reflect higher billings due to the weather sensitive nature of the natural gas business.
Overview
Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 61,700 residential, commercial and industrial customers in Roanoke, Virginia and the surrounding localities through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Natural gas service is provided at rates and for terms and conditions set by the Virginia State Corporation Commission (“SCC”).
Resources also invests in the Mountain Valley Pipeline ("MVP"), an interstate pipeline currently under construction, as a 1% participant through its RGC Midstream, LLC subsidiary ("Midstream") in addition to providing certain unregulated services through Roanoke Gas and its other subsidiaries. The unregulated operations of Roanoke Gas represent less than 2% of total revenues of Resources on an annual basis.
The Company’s utility operations are regulated by the 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 ("FERC") regulates the 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 has completed the transition to the 21% federal statutory income tax rate as a result of the Tax Cuts and Jobs Act ("TCJA") that was signed into law in December 2017. Since the implementation of the new tax rates, the Company has recorded a provision for refund related to estimated excess revenues collected from customers under approved billing rates that were designed to recover the operating expenses and provide a rate of return based on a federal tax rate of 34%. Beginning January 1, 2019, Roanoke Gas incorporated the effect of the 21% federal tax rate with the implementation of the new non-gas base rates as filed in its current rate application and began refunding the excess revenues associated with the change in the tax rate over the subsequent 12-month period. The Company also provided an estimated refund related to the new non-gas rates that were placed into effect on January 1, 2019. Additional information regarding the TCJA and non-gas base rate application is provided under the Regulatory and Tax Reform section below.
RGC RESOURCES, INC. AND SUBSIDIARIES
Over 98% of the Company’s annual revenues, excluding equity in earnings of MVP, are derived from the sale and delivery of natural gas to Roanoke Gas customers. The SCC authorizes the rates and fees 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.
As the Company’s business is seasonal in nature, 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 variations in weather and the cost of natural gas, the Company has certain approved rate mechanisms in place that help provide stability in earnings, adjust for volatility in the price of natural gas and provide a return on increased infrastructure investment. These mechanisms include a purchased gas adjustment factor ("PGA"), weather normalization adjustment factor ("WNA"), inventory carrying cost revenue ("ICC") and a Steps to Advance Virginia's Energy Plan ("SAVE") adjustment rider.
The Company's approved billing rates include a component designed to allow for the recovery of the cost of natural gas used by its customers. The cost of natural gas is considered a pass-through cost and is independent of the non-gas base rates of the Company. This rate component, referred to as the PGA, allows the Company to pass along to its customers increases and decreases in natural gas costs incurred by its regulated operations. On a quarterly basis, or more frequently if necessary, the Company files a PGA rate adjustment request with the SCC to adjust the gas cost component of its tariff rates depending on projected price and activity. Once administrative approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As actual costs will differ from projections used in establishing the PGA rate, the Company will either over-recover or under-recover its actual gas costs during the period. The difference between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset or liability. At the end of the annual deferral period, the balance is amortized over an ensuing 12-month period as those amounts are reflected in customer billings.
The WNA model reduces earnings volatility, related to weather variability in the heating season, by providing the Company a level of earnings protection when weather is warmer than normal and providing customers some price protection when the weather is colder than normal. The WNA is based on a weather measurement band around the most recent 30-year temperature average. Under the WNA, the Company recovers from its customers the lost margin (excluding gas costs) for the impact of weather that is warmer than normal or refunds the excess margin earned for weather that is colder than normal. The WNA mechanism used by the Company is based on a linear regression model that determines the value of a single heating degree day. For the three months and six months ended March 31, 2019, the Company accrued $46,000 in additional revenues under the WNA model for weather that was less than 1% warmer than normal and approximately $111,000 reduction in revenues for weather that was more than 1% colder than normal, respectively. For the corresponding periods last year, the Company accrued approximately $161,000 and $124,000 reduction in revenues for weather that was 3% and 2% colder than normal. The current WNA year ended on March 31, 2019, and once the SCC approves the billing factors, the Company will apply the amount to customers' bills.
The Company also has an approved rate structure in place that mitigates the impact of financing costs associated with 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. This ICC factor applied to the cost of 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 ICC revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing gas costs and lower inventory balances, the Company recognizes less carrying cost revenue as financing costs are lower. In addition, ICC revenues are impacted by the changes in the weighting of the components that are used to determine the weighted-average cost of capital. Total ICC revenues for the three and six month periods ended March 31, 2019 declined by approximately 12% from the same periods last year due to a combination of lower average natural gas storage balances and a reduction in the weighted average cost of capital factor used in calculating these revenues.
The Company’s non-gas base 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 non-gas rate application with the SCC utilizing historical and proforma information, including investment in natural gas facilities. Generally, investments related to extending service to new customers are recovered through the non-gas base rates currently in place. The additional investment in replacing and upgrading existing infrastructure is not recoverable until a formal rate application is filed and approved. The SAVE Plan, however, provides the Company with the ability to recover costs related to investments in qualified infrastructure projects on a prospective basis. The SAVE Plan provides a mechanism through which the Company may recover the related depreciation and expenses and provides a return on rate base for the related additional capital investments until such time that a
RGC RESOURCES, INC. AND SUBSIDIARIES
formal rate application is filed. As the Company has made significant expenditures since the last non-gas base rate increase in 2013, SAVE Plan revenues have continued to increase each year. With the filing of the new non-gas rate application, the SAVE Plan program has been reset as the prior qualified infrastructure investments were included in the derivation of the non-gas rates placed into effect in January 2019, subject to refund. Accordingly, SAVE Plan revenues declined by $1,146,000 for the three-month period ended March 31, 2019 compared to the same period last year and by approximately $1,014,000 for the corresponding six-month periods.
The Company is committed to safeguarding its information technology systems. These systems contain confidential customer, vendor and employee information as well as important financial data. There is risk associated with unauthorized access of this 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 attacks and similar incidents; however, there can be no guarantee that an incident will not occur. In the event of a cyber incident, the Company will execute its Security Incident Response Plan. The Company maintains cyber insurance to mitigate financial exposure that may result from a cyber incident.
Results of Operations
Three Months Ended
March 31, 2019
:
Net income increased by $1,204,161 for the three months ended
March 31, 2019
, compared to the same period last year. Improved quarterly performance is attributable to implementation of a non-gas rate increase, customer growth, equity in earnings from the investment in Mountain Valley Pipeline and lower income tax expense.
The tables below reflect operating revenues, volume activity and heating degree-days.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
2019
|
|
2018
|
|
Increase / (Decrease)
|
|
Percentage
|
Operating Revenues
|
|
|
|
|
|
|
|
Gas Utility
|
$
|
25,058,749
|
|
|
$
|
24,608,576
|
|
|
$
|
450,173
|
|
|
2
|
%
|
Non utility
|
216,210
|
|
|
309,397
|
|
|
(93,187
|
)
|
|
(30
|
)%
|
Total Operating Revenues
|
$
|
25,274,959
|
|
|
$
|
24,917,973
|
|
|
$
|
356,986
|
|
|
1
|
%
|
Delivered Volumes
|
|
|
|
|
|
|
|
Regulated Natural Gas (DTH)
|
|
|
|
|
|
|
|
Residential and Commercial
|
3,281,556
|
|
|
3,362,966
|
|
|
(81,410
|
)
|
|
(2
|
)%
|
Transportation and Interruptible
|
799,875
|
|
|
781,428
|
|
|
18,447
|
|
|
2
|
%
|
Total Delivered Volumes
|
4,081,431
|
|
|
4,144,394
|
|
|
(62,963
|
)
|
|
(2
|
)%
|
Heating Degree Days (Unofficial)
|
2,045
|
|
|
2,134
|
|
|
(89
|
)
|
|
(4
|
)%
|
Total operating revenues for the three months ended
March 31, 2019
, compared to the same period last year, increased primarily due to the implementation of higher non-gas rates partially offset by lower gas costs. The Company placed new non-gas base rates into effect for natural gas service rendered on or after January 1, 2019, subject to refund. The new rates incorporated revenues related to SAVE Plan activities through December 2018, as well as recovery of higher costs and non SAVE infrastructure additions since the last rate application. Total revenues have been reduced by an estimate for potential refunds, pending the completion of the audit by the SCC and the issuance of a final order on the rate application. The average commodity price of natural gas delivered during the current quarter was approximately 6% per decatherm lower than the same period last year. In addition, the prior year included a reserve of $358,901 associated with the estimated excess revenues billed to customers as a result of the reduction in the corporate federal income tax rate. No such reserve was recorded during the current quarter due to the implementation of new non-gas base rates.
See the Regulatory and Tax Reform section below for more information regarding the new non-gas base rates, provision for refund and the excess revenues related to the reduction in the corporate federal income tax rate.
RGC RESOURCES, INC. AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
2019
|
|
2018
|
|
Increase / (Decrease)
|
|
Percentage
|
Gas Utility Margin
|
|
|
|
|
|
|
|
Utility Revenues
|
$
|
25,058,749
|
|
|
$
|
24,608,576
|
|
|
$
|
450,173
|
|
|
2
|
%
|
Cost of Gas
|
12,771,338
|
|
|
13,743,277
|
|
|
(971,939
|
)
|
|
(7
|
)%
|
Gas Utility Margin
|
$
|
12,287,411
|
|
|
$
|
10,865,299
|
|
|
$
|
1,422,112
|
|
|
13
|
%
|
Regulated natural gas margins from utility operations (total utility revenues less utility cost of gas) increased from the same period last year primarily as a result of the implementation of higher non-gas base rates as filed under the rate application with the SCC. SAVE revenues declined by $1,145,504 as all related SAVE activities through December 31, 2018 were incorporated into the new non-gas base rates effective January 1, 2019. The result is a net increase in customer base charges of $1,185,278 and volumetric margin net of WNA of $1,063,626. The customer base charge and volumetric margins also include an estimated provision for refund. As noted above, the prior year included a reserve of $358,901 related to excess revenues to be refunded to customers due to the reduction in the federal income tax rate. Both the reserve for excess revenues associated with the reduction in the federal income tax rate and the new non-gas rates are subject to adjustment as the SCC completes their audit and ultimately issues a final order.
The components of and the change in gas utility margin are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2019
|
|
2018
|
|
Increase / (Decrease)
|
Customer Base Charge
|
$
|
4,331,767
|
|
|
$
|
3,146,489
|
|
|
$
|
1,185,278
|
|
Carrying Cost
|
92,932
|
|
|
106,162
|
|
|
(13,230
|
)
|
SAVE Plan
|
23,025
|
|
|
1,168,529
|
|
|
(1,145,504
|
)
|
Volumetric
|
7,777,889
|
|
|
6,921,210
|
|
|
856,679
|
|
WNA
|
46,412
|
|
|
(160,535
|
)
|
|
206,947
|
|
Other Gas Revenues
|
15,386
|
|
|
42,345
|
|
|
(26,959
|
)
|
Excess Revenue Refund
|
—
|
|
|
(358,901
|
)
|
|
358,901
|
|
Total
|
$
|
12,287,411
|
|
|
$
|
10,865,299
|
|
|
$
|
1,422,112
|
|
Operation and maintenance expenses increased by $225,195, or 6%, from the same period last year primarily related to increased compensation costs, contracted and professional services and amortization of regulatory assets partially offset by higher capitalized overheads Total compensation costs increased by $113,000 due to higher employment levels and wage increases over the prior year. Contracted and professional services increased by $99,000 related to operational support and general facility maintenance activities. The Company began amortizing certain regulatory assets that are currently being recovered in the new non-gas base rates. Total amortization expense for the quarter was $66,000 based on a proposed 5-year amortization period per the rate filing. Total capitalized overheads increased by $84,000 due to higher capital expenditures.
General taxes increased by $49,479, or 10%, associated with higher property and payroll taxes. Property taxes continue to increase corresponding to higher utility property balances related to ongoing infrastructure replacement, system reinforcements and customer growth. Increased compensation levels resulted in higher payroll taxes.
Depreciation expense increased by $170,597, or 10%, on a corresponding increase in utility plant investment.
Equity in earnings of unconsolidated affiliate increased by $506,662, more than triple last year, due to the extent of pipeline construction activities in the Mountain Valley Pipeline project. The corresponding earnings are primarily composed of allowance for funds used during construction ("AFUDC"). The level of construction activity resulted in a greater amount of AFUDC income. Additional information about the Company's investment in the MVP can be found under the Equity Investment in Mountain Valley Pipeline section below.
Other income (expense), net increased by $79,761 primarily due to the implementation of a revenue sharing incentive mechanism in 2018 related to the gas supply asset management agreement. See the Regulatory and Tax Reform section below for more information on revenue sharing. Furthermore, the adoption of ASU 2017-07,
Compensation - Retirement Benefits
, as discussed in Note 1, resulted in the components of net periodic benefit costs other than service cost being presented outside of
RGC RESOURCES, INC. AND SUBSIDIARIES
income from operations. As a result, the prior year amount has been adjusted retrospectively with the reclassification of a $30,633 net expense reduction from operations and maintenance to other income (expense) while the current period includes a net expense of less than $1,000 for these other net periodic benefit costs.
Interest expense increased by $259,463, or 41% due to a 35% increase in total average debt outstanding between quarters. The higher borrowing levels derived from the ongoing investment in MVP, financing expenditures in support of Roanoke Gas' capital budget and rising interest rates on the Company's variable-rate debt. Total borrowing under Midstream's credit facility increased by more than $21 million while the average interest rate increased 58 basis points. The Company's line-of-credit experienced a similar interest rate increase. As a result, the weighted-average effective interest rate on total Company debt increased from 3.77% in the second quarter of fiscal 2018 to 3.97% during the second quarter of fiscal 2019.
Income tax expense increased by $50,197 due to higher taxable income mostly offset by a reduction in the federal income tax rate and the amortization of excess deferred taxes on the regulated operations of Roanoke Gas. The federal income tax rate declined from the 24.3% blended rate for fiscal 2018 to the statutory rate of 21% in fiscal 2019 with the combined state and federal rate declining from 28.84% to 25.74%. In fiscal 2018, Roanoke Gas revalued the net deferred tax liability of its regulated operations and recorded a regulatory liability, which is being amortized as a credit to tax expense over a 28 year period corresponding with a comparable reduction in revenues through reduced billings to customers. This results in no impact to net income as the reduction in income tax expense corresponds to a reduction in revenues. See Regulatory and Tax Reform section for more information.
Six Months Ended
March 31, 2019
:
Net income increased by $1,578,861 for the six months ended
March 31, 2019
, compared to the same period last year due to the implementation of a non-gas rate increase, equity in earnings from the investment in Mountain Valley Pipeline and lower income tax rates.
The tables below reflect operating revenues, volume activity and heating degree-days.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31,
|
|
|
|
|
|
2019
|
|
2018
|
|
Increase / (Decrease)
|
|
Percentage
|
Operating Revenues
|
|
|
|
|
|
|
|
Gas Utility
|
$
|
46,095,330
|
|
|
$
|
43,128,570
|
|
|
$
|
2,966,760
|
|
|
7
|
%
|
Non utility
|
396,376
|
|
|
545,454
|
|
|
(149,078
|
)
|
|
(27
|
)%
|
Total Operating Revenues
|
$
|
46,491,706
|
|
|
$
|
43,674,024
|
|
|
$
|
2,817,682
|
|
|
6
|
%
|
Delivered Volumes
|
|
|
|
|
|
|
|
Regulated Natural Gas (DTH)
|
|
|
|
|
|
|
|
Residential and Commercial
|
5,647,630
|
|
|
5,579,675
|
|
|
67,955
|
|
|
1
|
%
|
Transportation and Interruptible
|
1,549,940
|
|
|
1,518,536
|
|
|
31,404
|
|
|
2
|
%
|
Total Delivered Volumes
|
7,197,570
|
|
|
7,098,211
|
|
|
99,359
|
|
|
1
|
%
|
Heating Degree Days (Unofficial)
|
3,605
|
|
|
3,631
|
|
|
(26
|
)
|
|
(1
|
)%
|
Operating revenues for the six months ended
March 31, 2019
increased over the same period last year due to the implementation of higher non-gas rates and higher gas costs. The Company placed new non-gas base rates into effect for natural gas service rendered on or after January 1, 2019, subject to refund. The new non-gas base rates were reflected in the Company's rate application with the SCC as filed in October 2018. The rates are subject to refund and the Company has recorded an estimated refund for the current quarter based on past history of rate awards approved by the SCC. The average commodity price of natural gas delivered during the first six months of fiscal 2019 was approximately 6% per decatherm higher than the same period last year. Natural gas commodity prices spiked during December due to weather, but have since returned to lower levels over the most recent quarter. The prior year included a reserve of $821,343 associated with the estimated excess revenues billed to customers as a result of the reduction in the corporate federal income tax rate. The current fiscal period reflects a reserve of $523,881 as the accrual for excess revenues ended with the implementation of new non-gas base rates, which incorporated the reduction in the federal income tax rate.
See the Regulatory and Tax Reform section below for more information.
RGC RESOURCES, INC. AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31,
|
|
|
|
|
|
2019
|
|
2018
|
|
Increase
|
|
Percentage
|
Gas Utility Margin
|
|
|
|
|
|
|
|
Utility Revenues
|
$
|
46,095,330
|
|
|
$
|
43,128,570
|
|
|
$
|
2,966,760
|
|
|
7
|
%
|
Cost of Gas
|
24,677,797
|
|
|
23,304,683
|
|
|
1,373,114
|
|
|
6
|
%
|
Gas Utility Margin
|
$
|
21,417,533
|
|
|
$
|
19,823,887
|
|
|
$
|
1,593,646
|
|
|
8
|
%
|
Regulated natural gas margins from utility operations increased from the same period last year for the same reason that margins increased for the quarter, implementation of higher non-gas base rates. As a result, customer base charges and non-gas volumetric margins increased by $1,201,167 and $1,155,544, respectively, net of the estimated refund. SAVE revenues declined by $1,014,411 during the same period. The reserve for excess revenues related to the reduction in federal income taxes declined by $297,462.
The components of and the change in gas utility margin are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31,
|
|
|
|
2019
|
|
2018
|
|
Increase / (Decrease)
|
Customer Base Charge
|
$
|
7,449,762
|
|
|
$
|
6,248,595
|
|
|
$
|
1,201,167
|
|
Carrying Cost
|
274,567
|
|
|
310,441
|
|
|
(35,874
|
)
|
SAVE Plan
|
1,230,537
|
|
|
2,244,948
|
|
|
(1,014,411
|
)
|
Volumetric
|
13,037,227
|
|
|
11,881,683
|
|
|
1,155,544
|
|
WNA
|
(110,922
|
)
|
|
(123,765
|
)
|
|
12,843
|
|
Other Gas Revenues
|
60,243
|
|
|
83,328
|
|
|
(23,085
|
)
|
Excess Revenue Refund
|
(523,881
|
)
|
|
(821,343
|
)
|
|
297,462
|
|
Total
|
$
|
21,417,533
|
|
|
$
|
19,823,887
|
|
|
$
|
1,593,646
|
|
Operation and maintenance expenses increased by $519,450, or 8%, from the same period last year due to higher compensation costs, contracted services, bad debt expense and amortization of regulatory assets partially offset by higher capitalized overheads. Total compensation costs increased by $331,000 due to higher employment levels and wage increases. The Company incurred $83,000 in contracted services related to the periodic clearing of the natural gas transmition line right-of-way and scheduled maintenance at the LNG facility. The Company began amortizing certain regulatory assets beginning January 1, 2019 resulting in an additional $66,000 in expense. Bad debt expense increased by $22,000 related to increased customer billings. Total capitalized overheads increased by $69,000 due to increased capital expenditures offset by lower LNG production during the period.
General taxes increased by $91,046, or 9%, associated with higher property and payroll taxes. The increase in property taxes reflect the ongoing investment in the utility infrastructure of Roanoke Gas while the higher payroll taxes correspond to compensation activity.
Depreciation expense increased by $341,194, or 10%, on higher utility plant investment.
Equity in earnings of unconsolidated affiliate increased by $920,900, due to the significant increase in the investment in the MVP project.
Other income (expense), net increased by $191,146 primarily due to the revenue sharing incentive mechanism approved in 2018, the reclassification of the components of net periodic benefit costs other than service cost from operations to a non-operating expense and timing of charitable contributions.
Interest expense increased by $463,600, or 37%, due to a 29% increase in total average debt outstanding and rising interest rates on the Company's variable-rate debt. Increased borrowing is attributable to the investment in MVP and funding of Roanoke Gas' capital budget. The weighted-average effective interest rate on total Company debt increased from 3.69% for the first six months of fiscal 2018 to 3.92% for the same period in fiscal 2019.
RGC RESOURCES, INC. AND SUBSIDIARIES
Income tax expense declined by $383,286 due to a reduction in the federal income tax rate, the amortization of excess deferred taxes on the regulated operations of Roanoke Gas and the valuation adjustment to the deferred taxes of the unregulated operations in the prior year. The federal income tax rate declined from the 24.3% blended rate for fiscal 2018 to the statutory rate of 21% in fiscal 2019. As discussed above and in the Regulatory and Tax Reform section below, Roanoke Gas is amortizing the regulatory liability related to the excess deferred taxes on the regulated operations into income tax expense with a corresponding reduction in revenues. During the first quarter of fiscal 2018, Resources revalued the deferred taxes of its unregulated operations, which resulted in $208,000 direct charge to income tax expense.
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 management 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's adjustments for the effect of the TCJA includes estimates related to the revaluation of deferred income tax and the refund of excess billings to customers pending final review and approval by the SCC. The Company believes these adjustments to be reasonable estimates of the financial effect of the tax change on the regulated operations of the Company. However, these estimates will be adjusted, if necessary, once the SCC completes its audit and approves the Company's proposed rates and methodology. If the SCC proposes any adjustment, it could result in increased refund amounts for customers and reductions in revenue. The Company has also recorded an estimate for refund related to the implementation of the new non-gas base rates effective January 1, 2019. This estimate is based on the results of prior rate proceedings and will be adjusted upon filing of the SCC's staff report and the issuance of a final order on the rate application.
The Company adopted ASU 2014-09,
Revenue from Contracts with Customers
, and subsequent guidance and amendments effective October 1, 2018. The adoption of the ASU did not have a significant effect on the Company's results of operations, financial position or cash flows as the new guidance resulted in essentially no change in the manner and timing in which the Company recognizes revenues. The primary operation of the Company is the sale and/or delivery of natural gas to customers (the performance obligation) based on SCC approved tariff rates (the transaction price). The Company recognizes revenue through billed and unbilled customer usage as natural gas is delivered. The Company also recognizes revenue through Alternative Revenue Programs, which are mechanisms authorized by the SCC that allow the Company to recognize or defer revenue independent of the collection from, or refund to, customers.
There have been no other changes to the critical accounting policies as reflected in the Company’s Annual Report on Form 10-K for the year ended September 30, 2018.
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 asset manager pays Roanoke Gas a monthly utilization fee. In accordance with an SCC order issued in 2018, a portion of the utilization fee will be retained by the Company with the balance passed through to customers through reduced gas costs.
Equity Investment in Mountain Valley Pipeline
On October 1, 2015, the Company, through its wholly-owned subsidiary Midstream, entered into an agreement to become a 1% member in Mountain Valley Pipeline, LLC (the "LLC"). The purpose of the LLC is to construct and operate the MVP, a FERC regulated natural gas pipeline connecting Equitran's gathering and transmission system in northern West Virginia to the Transco interstate pipeline in south central Virginia.
Management believes the investment in the LLC will be beneficial for the Company, its shareholders and southwest Virginia. In addition to the potential returns from the investment in the LLC, Roanoke Gas will benefit from access to an additional source of natural gas to its distribution system. Currently, Roanoke Gas is served by two pipelines and an LNG peak shaving facility. Damage to or interruption in supply from any of these sources, especially during the winter heating season, could have a significant impact on the Company's ability to serve its customers. A third pipeline would reduce the risk from such an event. In addition, the proposed pipeline path would provide the Company with a more economically feasible opportunity to provide natural gas service to previously unserved areas in southwest Virginia.
RGC RESOURCES, INC. AND SUBSIDIARIES
On October 13, 2017, FERC issued the MVP Certificate of Public Convenience and Necessity. Furthermore, since January 2018, FERC has issued several Notices to Proceed ("NTP"), which granted the LLC permission to begin construction activities. Since construction began, the LLC has encountered several challenges which have delayed the project, including weather issues, pipeline protesters and legal challenges to various federal and state permits resulting in stop orders and FERC intervention. Construction activities were limited during the just completed winter season but have since resumed. Certain permits have been vacated or stayed, which currently prevents the LLC from working in stream crossings or wetlands. In addition, FERC issued a stop work order that directed all construction activity to cease within a 25-mile exclusion zone in and around the Jefferson National Forest. The LLC continues to work with all related regulatory entities and judicial bodies to resolve these issues. The LLC managing partner has stated that completing the project during 2019 is unlikely; however the LLC managing partner continues to target a full in-service date in the fourth quarter of 2019.
Initially, the total project cost was estimated to be $3.5 billion. As a 1% member in the LLC, Midstream's cash contribution was expected to be approximately $35 million. As a result of the issues described above, the LLC revised the project cost to an estimated $4.6 billion with Midstream's estimated cash investment increasing to $46 million. Midstream negotiated amendments to its two 5-year unsecured Promissory Notes to increase borrowing limits from $38 million to $50 million. Midstream was able to obtain access to the additional capital with no changes to existing provisions under the notes.
Most of the current earnings from the investment in MVP relate to AFUDC income generated by the deployment of capital in the design, engineering, materials procurement, project management and construction of the pipeline. AFUDC is an accounting method whereby the costs of debt and equity funds used to finance facility infrastructure are credited to income and charged to the cost of the project. As investment in the MVP grows, so will the amount of AFUDC recognized until the pipeline is placed in service. Earnings after the pipeline becomes operational will be derived from the fees charged for transporting natural gas through the pipeline.
In 2018, Midstream became a participant in the MVP Southgate project ("Southgate"), to construct a 70-mile pipeline extending from the MVP mainline at the Transco interconnect in Virginia to delivery points in North Carolina. Midstream is a less than 1% investor in the Southgate project and, based on current project cost estimates, will invest between $1.8 million and $2.5 million toward the project. Midstream's participation in the Southgate project is for investment purposes only. The Southgate in-service date is currently targeted for the end of calendar 2020.
Regulatory and Tax Reform
On October 10, 2018, Roanoke Gas filed a general rate case application requesting an annual increase in customer non-gas base rates of approximately $10.5 million. This application incorporates into the non-gas base rates the impact of tax reform, non-SAVE utility plant investment, increased operating costs, recovery of regulatory assets associated with eligible safety activity costs ("ESAC") and approximately $4.7 million in annual SAVE plan revenues previously billed through the SAVE rider. The new non-gas base rates were placed into effect for gas service rendered on or after January 1, 2019, subject to refund, pending audit and final order by the SCC. The SCC staff is currently conducting their audit of the rate application, with their report expected by the end of June 2019. A hearing on the rate application is scheduled for August with a final order not expected until later in 2019.
Historically, the Company has not received the full rate increase requested in their rate applications. The SCC will conduct a thorough audit and make adjustments to the requests based on updated information, differences in assumptions, disallowance of certain costs and precedents set by rate awards at other companies. Therefore, management has recorded a provision for refund in current regulatory liabilities associated with these new non-gas rates. As there is currently not sufficient information to determine the full extent of proposed adjustments and recommendations by the SCC staff nor the ultimate result from the subsequent hearing, management based the refund reserve on previously approved rate awards as compared to initial rate requests. The actual refund could be more or less depending on the outcome of both the staff's audit and the hearing. As more information becomes available, the Company will refine its estimate for refund; however, the actual rate award will not be finalized until the SCC issues its order.
The general rate case application incorporated the effects of tax reform, which reduced the federal tax rate for the Company from 34% to 21%. Roanoke Gas recorded two regulatory liabilities to account for this change in the federal tax rate. The first regulatory liability related to the excess deferred taxes associated with the regulated operations of Roanoke Gas. As Roanoke Gas had a net deferred tax liability, the reduction in the federal tax rate required the revaluation of these excess deferred income taxes to the 21% rate at which the deferred taxes are expected to reverse. The excess net deferred tax liability for Roanoke Gas' regulated operations was transferred to a regulatory liability, while the revaluation of excess deferred taxes on the unregulated operations of the Company were flowed into income tax expense in the first quarter of fiscal 2018. A majority of the regulatory liability for excess deferred taxes was attributable to accelerated tax depreciation related to utility property. In order to not
RGC RESOURCES, INC. AND SUBSIDIARIES
violate the IRS normalization rules, these excess deferred income taxes must be flowed back to customers and through tax expense based on the average remaining life of the corresponding assets, which approximates 28 years. As of March 31, 2019, Roanoke Gas had approximately $11,200,000 in both current and non-current portions of the net regulatory liability.
The second regulatory liability relates to the excess revenues collected from customers. The non-gas base rates used since the passage of the TCJA in December 2017 through December 2018 were derived from a 34% federal tax rate. As a result, the Company over-recovered from its customers the difference between the federal tax rate at 34% and the 24.3% blended rate in fiscal 2018 and 21% in fiscal 2019. To comply with an SCC directive issued in January 2018, Roanoke Gas recorded an estimated refund for the excess revenues collected in fiscal 2018 and the first quarter of fiscal 2019.
Beginning with the implementation of the new non-gas base rates in January 2019, Roanoke Gas began returning the excess deferred income taxes over the 28-year period and the excess revenues to customers over a 12-month period. The estimated refund amounts for both the excess deferred taxes and the excess revenues associated with the reduction in the federal income tax rate are subject to review and adjustment by the SCC, which is being done in connection with their audit of the rate case application. The Company will record any such adjustments as required by an SCC order.
Since its last rate case, Roanoke Gas has deferred ESAC costs attributable to compliance and safety related expenses. These expenses were above and beyond a base line for those costs previously provided for in non-gas base rates and have been included in the current rate application for recovery over a five year period. If the SCC would deny recovery of any of these costs, Roanoke Gas would adjust the value of the regulatory assets to the amount that would ultimately be realized by the Company.
The Company continues to recover the costs of its infrastructure replacement program through its SAVE Plan. The original SAVE Plan was designed to facilitate the accelerated replacement of aging 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. Since the implementation and approval of the original SAVE Plan in 2012, the Company has modified, amended or updated it each year to incorporate various qualifying projects. On September 28, 2018, the SCC issued its order approving the 2019 SAVE Plan and SAVE rider effective January 1, 2019, focusing on the ongoing replacement of pre-1973 plastic pipe. All previous SAVE investment through December 31, 2018 has been incorporated into the rate application. The new SAVE Plan Rider reflects only the recovery of qualifying SAVE Plan investments made since the beginning of January 2019. As a result, the 2019 SAVE Plan Rider is expected to provide approximately $362,000 in revenue for the nine months ended September 30, 2019. In addition, the SCC also approved the true-up factor for the 2017 SAVE Plan, which will refund approximately $163,000 in excess SAVE Plan revenues to customers.
As noted above, Roanoke Gas contracts with a third party asset manager to manage its pipeline transportation, storage rights and gas supply inventories and deliveries. In return for the right to utilize the excess capacities of the transportation and storage rights, the asset manager credits Roanoke Gas monthly for an amount referred to as a utilization fee. In June 2018, the SCC issued an order, retroactive to April 1, 2018, approving implementation of an incentive mechanism, whereby the Company shares the utilization fee with its customers. Under the incentive mechanism beginning April 1 each year, customers receive the initial $700,000 of the utilization fee collected through reduced gas costs, and thereafter, every additional dollar received during the annual period is split 25% to the Company and 75% to its customers.
On February 7, 2019, the SCC issued a final order granting a Certificate of Public Convenience and Necessity ("CPCN") to furnish gas service to all of Franklin County. If the Company does not furnish gas service to the area so designated within five years of the date of the order, the CPCN granting authority to serve Franklin County will be terminated.
Roanoke Gas' 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 every five years. The last depreciation study was completed and implemented in fiscal 2014. The Company is currently in the process of conducting a new depreciation study to incorporate all of the new and replacement infrastructure and equipment placed in service since the last study. The Company anticipates filing the new depreciation study with the SCC in June for review and approval. Once approved, any changes are expected to be implemented in the current fiscal year. The potential impact of the new depreciation study is not known at this time.
Capital Resources and Liquidity
Due to the capital intensive nature of the utility business, as well as the related weather sensitivity, the Company’s primary capital needs are the funding of its utility plant capital projects, investment in the MVP, the seasonal funding of its natural gas
RGC RESOURCES, INC. AND SUBSIDIARIES
inventories and accounts receivable and the payment of dividends. To meet these needs, the Company relies on its operating cash flows, line-of-credit agreement, long-term debt and equity capital.
Cash and cash equivalents increased by $1,720,152 for the six-month period ended March 31, 2019, compared to a $4,776,934 increase for the same period last year. The following table summarizes the sources and uses of cash:
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|
|
|
|
|
|
|
|
|
Six Months Ended March 31,
|
|
2019
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|
2018
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Cash Flow Summary
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|
|
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Net cash provided by operating activities
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$
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10,933,123
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|
|
$
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10,648,528
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Net cash used in investing activities
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(24,279,040
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)
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|
(13,851,993
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)
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Net cash provided by financing activities
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15,066,069
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|
|
7,980,399
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Increase in cash and cash equivalents
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$
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1,720,152
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|
|
$
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4,776,934
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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, contribute to working capital levels and the 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 increases in natural gas storage levels, rising customer receivable balances and construction activity.
Cash flow provided by operations is primarily driven by net income, depreciation, reductions in natural gas storage inventory and increases in accounts receivable during the first six months of the fiscal year. Cash flow from operating activities increased over the same period last year by $284,595, primarily related to several offsetting items. Net income increased by nearly $1.6 million; however, a significant portion of the increase was attributable to the non-cash equity in earnings from the investment in MVP. Over-collections of gas cost increased by more than $2.6 million over the same period last year. Gas prices spiked in December and the futures prices indicated the natural gas commodity prices would remain at an elevated level during the winter months. Based on this information, the Company filed its quarterly PGA adjustment reflecting higher prices; however, commodity prices returned to lower levels during the second fiscal quarter resulting in the increase in over-collections. Accounts receivable balances increased by $2.7 million over the same period last year primarily as a result of the implementation of new non-gas rates and the higher gas cost component in the PGA factor. A summary of the cash provided by operations is provided below: