Supplemental Gas and Oil Information (Unaudited)

The Company is making the following supplemental disclosures of gas and oil producing activities, in accordance with accounting standards for extractive activities - oil and gas and SEC Regulation S-X.

The Company uses the successful efforts accounting method for its gas and oil properties and all properties are in the United States.

The substantial majority of the following information relates to cost-of-service gas and oil properties managed and developed by Wexpro and governed by the Wexpro agreements.

In December 2014, Wexpro acquired the Canyon Creek acquisition and in September 2013, Wexpro completed the Trail acquisition. Under the terms of the Wexpro II Agreement, these properties were submitted to the PSCU and PSCW (the Commissions). The Commissions approved the Canyon Creek and the Trail acquisition's in the fourth quarter of 2015 and the first quarter of 2014, respectively.

The 2015 and 2014 supplemental gas and oil information includes these acquisitions, as applicable. See Note 18 for additional information on these acquisitions.

Capitalized Costs

Capitalized costs of gas and oil properties and the related amounts of accumulated depreciation, depletion and amortization are shown below:



	December 31,
	2015			2014
	(in millions)
Wexpro
Proved properties	$	1,649.2		$	1,675.6
Unproved properties	5.2			12.8
Total Wexpro capitalized costs	1,654.4			1,688.4
Accumulated depreciation, depletion and amortization	(789.9		)	(757.3		)
Net Wexpro capitalized costs	864.5			931.1
Net Questar Gas capitalized costs	5.8			6.4
Net capitalized costs	$	870.3		$	937.5

Costs Incurred

The costs incurred for gas and oil development activities are displayed in the table below. The costs incurred to develop proved undeveloped reserves were $22.5 million in 2015, $28.9 million in 2014 and $106.3 million in 2013.



	Year Ended December 31,
	2015		2014		2013
	(in millions)
Property acquisition
Unproved	$	4.8	$	11.9	$	0.3
Proved	13.8		54.1		106.4
Exploration (capitalized and expensed)	0.7		1.6		—
Development	27.7		49.1		133.1
Total costs incurred	$	47.0	$	116.7	$	239.8

Results of Operations

Following are the results of operations for gas- and oil-producing activities, excluding corporate overhead and interest costs:



	Year Ended December 31,
	2015			2014			2013
	(in millions)
Revenues
From unaffiliated customers	$	22.9		$	35.6		$	45.1
From affiliated company⁽¹⁾	319.1			350.3			294.8
Total revenues	342.0			385.9			339.9
Production costs	50.1			67.5			57.5
Exploration expenses	0.7			1.6			—
Depreciation, depletion and amortization	99.4			100.5			85.8
Abandonment and impairment	12.5			2.0			—
Total expenses	162.7			171.6			143.3
Revenues less expenses	179.3			214.3			196.6
Income taxes	(59.6		)	(71.4		)	(70.5		)
Results of operations for gas- and oil-producing activities (excluding corporate overhead and interest costs)	$	119.7		$	142.9		$	126.1

⁽¹⁾Primarily represents revenues received from Questar Gas pursuant to the Wexpro agreements. Revenues include reimbursement of general and administrative expenses amounting to $28.9 million in 2015, $30.5 million in 2014 and $27.5 million in 2013.

Estimated Quantities of Proved Gas and Oil Reserves

Estimates of proved gas and oil reserves have been prepared in accordance with professional engineering standards and the Company's established internal controls. The estimates were prepared by Wexpro's reservoir engineers, individuals who possess professional qualifications and demonstrated competency in reserves estimation and evaluation. SEC guidelines with respect to standard economic assumptions are not applicable to the large proportion of Wexpro gas reserves that are managed, developed, produced and delivered to Questar Gas at cost of service. The SEC acknowledges this potential circumstance and provides that companies may give appropriate recognition to differences arising because of the effect of the rate-making process. Accordingly, in cases where differences arise because of the effect of the rate-making process, Wexpro uses a minimum-producing rate or maximum well-life limit to determine the ultimate quantity of reserves attributable to each well.

The Company annually reviews all proved undeveloped reserves to ensure an appropriate plan for development exists. All proved undeveloped reserves are converted to proved developed reserves within five years of the proved undeveloped reserve booking. At December, 2015, all of the Company's proved undeveloped reserves were scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves. Wexpro converted 94% of prior year-end proved undeveloped reserves to developed status in 2015, 7% in 2014 and 42% in 2013.

Revisions of prior estimates reflect the addition of new proved undeveloped reserves associated with current five-year development plans, revisions to prior proved undeveloped reserves, revisions to infill drilling development plans, as well as the transfer of proved undeveloped reserves to unproved reserve categories due to changes in development plans. The negative revisions reflected in the 2013 reserve estimates are due in part to an increase in well spacing in the Pinedale field based on 2013 drilling results. The negative revisions in 2014 are primarily due to the impact on proved undeveloped reserves from significant changes in the Company's five-year development plans based on the drop in natural gas and oil prices at the end of 2014. The negative revisions in 2015 were due to lower natural gas and oil prices in 2015.

In establishing reserves, the SEC allows the use of techniques that have been field tested and demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In general, the Company uses numerous data elements and analysis techniques in the estimation of proved reserves. These data elements and techniques include, but are not limited to, production tests, well performance data, decline curve analysis, wireline logs, core data, pressure transient analysis, seismic data and interpretation, and material balance calculations. The Company utilizes these reliable technologies to book proved reserves, however, no reserves were recorded from increasing recovery factor estimates or from extending down-dip reservoir limits associated with the use of reliable technology.

Wexpro's estimates of proved reserves were made by the Company's engineers and are the responsibility of management. The Company requires that reserve estimates be made by qualified reserves estimators (QREs), as defined by the Society of Petroleum Engineers' standards. The QREs interact with engineering, land, and geoscience personnel to obtain the necessary data for projecting future production, costs, net revenues and ultimate recoverable reserves. Management approves the QREs' reserve estimates annually. All QREs receive ongoing education on the fundamentals of SEC reserves reporting through internal and external training over the policies for estimating and recording reserves in compliance with applicable SEC definitions and guidance.

Gas and oil reserve estimates are subject to numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and timing of development expenditures. The accuracy of these estimates depends on the quality of available data and on engineering and geological interpretation and judgment. Reserve estimates are imprecise and will change as additional information becomes available. Ownership interests in properties may change due to claims of ownership rights. Estimates of economically recoverable reserves prepared by different engineers, or by the same engineers at different times, may vary significantly. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. In addition, the estimation process involves economic assumptions relating to commodity prices, production costs, severance and other taxes, capital expenditures and remediation costs. Changes in field-development plans will impact the reporting of reserves because the Company limits the recording of proved undeveloped reserves to those that are expected to be developed within the next five years. Actual results most likely will vary from the estimates. Any significant variance from these assumptions could affect the recoverable quantities of reserves attributable to any particular property and the classifications of reserves.

Estimated quantities of proved gas and oil reserves are set forth below:



	Natural Gas		Oil and NGL		Natural Gas Equivalents
	(Bcf)		(Mbbl)		(Bcfe)
Proved Reserves
Balances at December 31, 2012	697.2		6,169		734.2
Revisions of previous estimates	(112.8	)	(1,348	)	(120.8	)
Extensions and discoveries	153.5		857		158.6
Purchase of reserves in place	133.9		556		137.2
Production	(60.6	)	(617	)	(64.3	)
Balances at December 31, 2013	811.2		5,617		844.9
Revisions of previous estimates	(220.2	)	(442	)	(222.7	)
Extensions and discoveries	4.0		205		5.2
Purchase of reserves in place	35.9		157		36.8
Sale of reserves in place	(0.5	)	(219	)	(1.9	)
Production	(64.3	)	(587	)	(67.8	)
Balances at December 31, 2014	566.1		4,731		594.5
Revisions of previous estimates	(58.7	)	(1,424	)	(67.2	)
Extensions and discoveries	79.7		320		81.6
Purchase of reserves in place	10.8		29		11.0
Sale of reserves in place	(3.2	)	—		(3.2	)
Production	(62.1	)	(464	)	(64.9	)
Balances at December 31, 2015	532.6		3,192		551.8

Proved Developed Reserves
Balances at December 31, 2012	523.9		4,967		553.7
Balances at December 31, 2013	560.0		4,384		586.3
Balances at December 31, 2014	552.9		4,678		581.0
Balances at December 31, 2015	453.3		2,885		470.7

Proved Undeveloped Reserves
Balances at December 31, 2012	173.3		1,202		180.5
Balances at December 31, 2013	251.2		1,233		258.6
Balances at December 31, 2014	13.2		53		13.5
Balances at December 31, 2015	79.3		307		81.1

Standardized Measure of Future Net Cash Flows Relating to Non-Cost-of-Service Proved Reserves

The above December 31, 2015 and 2014 balances of total proved reserves includes 10.4 of non-cost of service reserves associated with the December 2015 Vermillion Basin acquisition and 36.6 Bcfe of non-cost-of-service reserves associated with the December 2014 Canyon Creek acquisition. In the fourth quarter of 2015, the Commissions approved the inclusion of the Canyon Creek acquisition in the Wexpro II Agreement, effective December 1, 2015.

The standardized measure of future net cash flows applies only to non-cost-of-service reserves. Information on the standardized measure of future net cash flows has not been included for cost-of-service activities because the operations of and return on investment for such properties are regulated by the Wexpro agreements.

Future net cash flows were calculated at December 31, 2015 by applying prices used in estimating 2015 reserves. Year-end production costs, development costs and appropriate statutory income tax rates, with consideration of future tax rates already legislated, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties.

The assumptions used to derive the standardized measure of future net cash flows, including the 10% discount rate, are those required by accounting standards and do not necessarily reflect the Company's expectations. The usefulness of the standardized measure of future net cash flows is impaired because of the reliance on reserve estimates and production schedules that are inherently imprecise. Furthermore, information contained in the following disclosure may not represent realistic assessments of future cash flows, nor should the standardized measure of future net cash flows be viewed as representative of the current value of the Company's reserves.

Management considers a number of factors when making investment and operating decisions. These include estimates of probable and proved reserves and varying price and cost assumptions considered more representative of a range of anticipated economic conditions. The standardized measure of future net cash flows relating to non-cost-of-service proved reserves is presented in the table below:



	December 31,			December 31,
	2015			2014
	(in millions)			(in millions)
Future cash inflows	$	29.5		$	190.7
Future production costs	(15.7		)	(65.9		)
Future income tax expenses	(4.8		)	(43.7		)
Future net cash flows	9.0			81.1
10% annual discount for estimated timing of net cash flows	(3.6		)	(34.4		)
Standardized measure of discounted future net cash flows	$	5.4		$	46.7

The principal sources of change in the standardized measure of future net cash flows relating to non-cost-of-service proved reserves are presented in the table below:



	Year Ended December 31,			Year Ended December 31,
	2015			2014
	(in millions)			(in millions)
Balance at beginning of year	$	46.7		$	—
Net increase due to purchases of reserves in place	6.0			46.8
Transfer to cost-of-service properties	(25.9		)	—
Sales of gas and oil produced during the period, net of production costs	(8.4		)	(1.5		)
Net change in prices and production costs related to future production	(31.0		)	0.8
Net change due to revisions of quantity estimates	(0.4		)	—
Accretion of discount	6.7			0.6
Net change in income taxes	11.7			—
Net Change	(41.3		)	46.7
Balance at end of year	$	5.4		$	46.7