Supplemental Natural Gas Disclosures

During 2015 we did not have any exploratory wells or related costs.

The following unaudited information regarding our gas reserves has been prepared and is presented pursuant to requirements of the Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB).

One of our subsidiaries owns working interests in certain natural gas properties, all of which are located in Wyoming County, Pennsylvania, within the Marcellus Shale. Our ownership of working interests in natural gas properties is accounted for as an undivided interest, whereby we reflect our proportionate share of the underlying assets, liabilities, revenues and expenses. Our working interest represents our share of the costs and expenses incurred primarily to develop the underlying leaseholds and to produce natural gas while our net revenue interest represents our share of the revenues from the sale of natural gas. The net revenue interest is less than our working interest as the result of royalty interest due to others. We are not the operator of these natural gas properties. We purchase a significant amount of natural gas as a feedstock for the production of ammonia. Management considers this acquisition as an economic hedge against a potential rise in natural gas prices in the future for a portion of our future natural gas production requirements.

Our natural gas reserves are based on estimates and assumptions, which affect our DD&A calculations. Our independent consulting petroleum engineer, with our assistance, prepares estimates of natural gas reserves based on available relevant data and information. For DD&A purposes, and as required by the guidelines and definitions established by the SEC, the reserve estimates are based on average natural gas prices during the 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month.

Our proven natural gas properties are reviewed for impairment on a field-by-field basis and nonproducing leasehold costs are reviewed for impairment on a property-by-property basis.

During September 2015, we recognized an impairment charge of $39.7 million to write-down the carrying value of our working interest in natural gas properties in the Marcellus Shale region to their estimated fair value of $22.5 million. The impairment charge represented the amount by which the carrying value of these natural gas properties exceeded the estimated fair value and was therefore deemed impaired. The estimated fair value was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and prices at which we reasonably expect natural gas will be sold, including information provided by our independent consulting petroleum engineer. The impairment was due to the decline in forward prices for natural gas, large natural gas price differentials in the Marcellus Shale region and changes in the drilling plans of these natural gas properties.

The independent consulting petroleum engineering firm of Pinnacle Energy Services of Oklahoma City, Oklahoma calculated the Company’s natural gas reserves as of December 31, 2015 using volumetric analysis of the reservoir and rate decline analysis for existing producers. (See exhibit 23.2 and exhibit 99.1 included in this report). The process of estimating proved reserves and future net cash flows is complex involving decisions and assumptions in evaluating the available engineering and geologic data and prices natural gas and the cost to produce these reserves and other factors, many of which are beyond our control. As a result, these estimates are imprecise and should be expected to change as future information becomes available. These changes could be significant. In addition, this information should not be construed as being the current fair market value of our proved reserves.

As a non-operator of our natural gas properties, we rely on information provided from the operator which is given to our independent consulting petroleum engineering firm for use in the preparation of our reserve estimates. The reserve estimates are reviewed by our Chemical accounting group for accuracy and checked for consistency in its preparation along with validating the assumptions provided by the operator based on actual performance. Additionally, members of management, meet with the operator quarterly to review our properties and discuss performance.

Supplemental Natural Gas Disclosures (continued)

Capitalized costs related to our oil and gas producing activities are as follows:

Capitalized Costs Relating to

Natural Gas Producing Activities

At December 31, 2015

(In thousands)

Proved natural gas properties

76,277

Accumulated depreciation, depletion and amortization and

valuation allowances

(54,071

)

Net capitalized costs

22,206

Estimated Quantities of Proved Natural Gas Reserves

Estimated quantities of proved natural gas reserves are summarized as follows:

	Proved			Proved
	Developed			Undeveloped
	Reserves			Reserves
	Natural			Natural
	Gas (MMcf)			Gas (MMcf)
Year-end 2014		27,000			32,193
Revisions of previous estimates		1,549			(24,097	)
Production		(3,742	)		—
Year-end 2015		24,807			8,096

The revisions of previous estimates for proved undeveloped reserves is primarily attributable to 25,812 MMcf of reserves which are no longer projected to be developed within five years from the date they were added to the proved undeveloped reserves due to low commodity prices and a delayed timing of the development plan put in place by the operator. There were no transfers of PUD reserves to proved developed during 2015. There are only four locations that remain in the PUD category at the end of 2015 and we anticipate that all of these locations will be drilled and converted to PDP within five years from the date they were added based on the operator’s current development plan.

We do not have any estimated reserves of crude oil, synthetic oil, synthetic gas or products of other non-renewable natural resources that are intended to be upgraded into synthetic oil and synthetic gas.

In 2015 reserve additions from new wells drilled and completed during the year are shown accounted for using the successful efforts method for our share of working interest wells applying industry practices for new well classifications. There were 4 new well additions in 2015.

Estimates of future cash flows from proved natural gas reserves are shown in the following table. Estimated income taxes are calculated by applying the appropriate tax rates to the estimated future pre-tax net cash flows less depreciation of the tax basis of properties and the statutory depletion allowance.

	2015
	(In thousands)
Future cash inflows	$	32,476
Future production and development costs		(11,345	)
Future income tax expenses		—
Future net cash flows		21,131
10% annual discount for estimated timing of cash flows		(9,069	)
Standardized measure of discounted future net cash flows		12,062

Supplemental Natural Gas Disclosures (continued)

Future net cash flows were computed using prices used in estimating proved natural gas reserves, year-end costs, and statutory tax rates (adjusted for tax deductions) that relate to proved natural gas reserves.

Changes in the standardized measure of discounted future net cash flow follows:

	For the Year
	2015
	(In thousands)
Net change in sales prices and production costs	$	(49,562	)
Net change in future development costs		15,563
Sales of natural gas, net of production costs		(10,088	)
Net change due to revisions of quantity estimates		(9,705	)
Accretion of discount		(6,346	)
Net change in income taxes		14,207
Other		3,818
Aggregate change for the year	$	(42,113	)

Our working interests and the associated net revenue interests are contractually defined and based on a percentage of production at prevailing market prices. We receive our percentage of production in cash. Similarly, our working interests and the associated net revenue interests are contractually defined and we pay our proportionate share of the capital and operating costs for the development and operation of the well. Our revenues fluctuate based on changes in the market prices for natural gas, the decline in production from existing wells, and other factors affecting natural gas exploration and production activities, including the cost of development and production.

Our average sales price of gas produced during the year was $1.01 per Mcf and our average production costs were $0.23 per Mcf. Our gross productive natural gas wells as of December 31, 2015 were 34 and our net productive gas wells when applying our working interests were 4.08. We do not operate any wells and there were no wells in process of drilling at December 31, 2015.