---

---

•	changes in worldwide production volumes and demand, including economic conditions that might impact demand;

•	volatility of commodity prices for crude oil, natural gas and NGLs and the risk of an extended period of depressed prices;

•	reductions in the borrowing base under our revolving credit facility;

•	impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations;

•	declines in the value of our crude oil, natural gas and NGLs properties resulting in further impairments;

•	changes in estimates of proved reserves;

---

•	inaccuracy of reserve estimates and expected production rates;

•	potential for production decline rates from our wells being greater than expected;

•	timing and extent of our success in discovering, acquiring, developing and producing reserves;

•	availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production;

•	timing and receipt of necessary regulatory permits;

•	risks incidental to the drilling and operation of crude oil and natural gas wells;

•	future cash flows, liquidity and financial condition;

•	competition within the oil and gas industry;

•	availability and cost of capital;

•	our success in marketing crude oil, natural gas and NGLs;

•	effect of crude oil and natural gas derivatives activities;

•	impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events;

•	cost of pending or future litigation;

•	effect that acquisitions we may pursue have on our capital expenditures;

•	our ability to retain or attract senior management and key technical employees; and

•	success of strategic plans, expectations and objectives for our future operations.

•

Multi-year project inventory in premier crude oil, natural gas and NGLs plays. We have a significant operational presence in the Wattenberg Field, a key U.S. onshore basin, and have identified a substantial inventory of 791 gross proved undeveloped horizontal drilling locations and approximately 1,400 probable horizontal drilling locations in this play. These location counts are based on wells expected to be drilled with an average lateral length of approximately 4,700 feet. Further, with our leaseholds in Ohio, we have the ability to pursue developmental drilling in the emerging Utica Shale play and are focusing our development in the condensate and wet natural gas window of the play. We believe that this inventory will allow us to continue to grow our reserves and production, and that, with respect to the Wattenberg Field in particular, the majority of our projects will generate attractive rates of return at current commodity price projections and our current projected cost structure.

---

•

Strong liquidity position. As of December 31, 2015, we had a total liquidity position of $402.2 million, comprised of $0.9 million of cash and cash equivalents and $401.3 million available for borrowing under our revolving credit facility. We had $37.0 million outstanding on our revolving credit facility as of December 31, 2015. Our liquidity position will be reduced by $115 million upon the maturity of our 3.25% convertible senior notes in May 2016. Pursuant to the related indenture, we will settle the principal amount of the notes in cash and issue common stock for the excess conversion value upon maturity. In September 2015, we completed the semi-annual redetermination of the borrowing base under our revolving credit facility, which resulted in the reaffirmation of the borrowing base at $700 million. We elected to maintain the aggregate commitment at $450 million. Considering the additional $250 million borrowing base available under our revolving credit facility, subject to certain terms and conditions of the agreement, our liquidity position as of December 31, 2015 could have been $652.2 million.

•

Significant control in our core areas. Our operational control is enhanced by the fact that substantially all of our Wattenberg Field leasehold position is held-by-production. We remain flexible in terms of rig activity and capital deployment due to short-term rig contracts and held-by-production acreage. As a result, we can adjust our drilling plans if commodity prices deteriorate further in order to balance cash flows from operations and cash flows from investing activities, which primarily consist of our capital expenditures. Our leaseholds that are held-by-production further enhance our operational control by providing us flexibility in selecting drilling locations based upon various operational criteria. Additionally, as a result of successfully executing our strategy of acquiring largely concentrated acreage positions with a high working interest, we operate and manage approximately 87% of the wells in which we have an interest. Our high percentage of operated properties enables us to exercise a significant level of control with respect to drilling, production, operating and administrative costs, in addition to leveraging our base of technical expertise in our core operating areas.

•

2016 derivative program. We have hedged a portion of our short-term future exposure to commodity price fluctuations by entering into crude oil and natural gas collars, fixed-price swaps and basis protection swaps. While our derivative program limits the upside benefits we may otherwise receive during periods of higher commodity prices, the program helps protect our cash flows, borrowing base and liquidity during periods of depressed commodity prices. As of December 31, 2015, we had hedge positions covering approximately 4,140 MBbls of 2016 crude oil production, or approximately 45% to 50% of our expected crude oil production for the year. These hedges were at a weighted-average minimum price of $77.26 per Bbl and a weighted-average maximum price of $86.88 per Bbl. As of the same date, we had hedged approximately 29.8 Bcf, or approximately 59% to 65%, of our expected natural gas production in 2016, at a weighted-average minimum price of $3.62 per Mcf and a weighted-average maximum price of $3.72 per Mcf. As of December 31, 2015, we had hedged a much lower percentage of our expected production for the next 12 to 24 months than we have hedged historically.

•

Technology focused team. We have a proven track record of continuing improvement in both costs and productivity of our well operations. Recently, our teams have focused on transitioning to multi-well pad drilling, extended laterals, increased frac stage density, enhanced frac design and drilling efficiencies. In 2015, we introduced tighter frac stage density and, in 40% of our spuds, extended reach laterals that are 6,500 to 7,000 feet in length. We also began testing plug-and-perf completions along with diverting agents that have provided an uplift to our new well production. We have completed wells at various densities ranging from 16 wells per section equivalent to 26 wells per section equivalent, providing added information on the reserves that can potentially be recovered. Finally, our drilling team has made great strides in reducing drill times for one mile laterals from an average of approximately 14 days to seven days spud-to-spud over the year.

•

Track record of reserve and production growth. Our proved reserves have grown from 50 MMBoe at December 31, 2010, after adjusting for subsequent divestitures, to approximately 273 MMBoe at December 31, 2015, representing a compound annual growth rate (“CAGR”) of 40%. During the same time period, our proved crude oil and NGL reserves grew at a CAGR of 42%. Our annual production from continuing operations grew from 3.3 MMBoe in 2010 to 15.4 MMBoe in 2015, representing a CAGR of 36%. Future development of the Wattenberg Field provides the opportunity to add further proved, probable and possible reserves to our portfolio. Similarly, we believe the Utica Shale provides the opportunity for additional proved, probable and possible reserves in a more favorable crude oil and natural gas pricing environment. As a result of data generated from our downspacing testing in the Wattenberg Field, Ryder Scott Company, L.P. (“Ryder Scott”), our independent petroleum engineering consulting firm, has increased the density of our proven undeveloped locations, year-over-year, in the Niobrara formation. In general, at December 31, 2013, Niobrara PUD locations were booked at an equivalent density of six wells per section, at December 31, 2014, Niobrara PUD locations were booked at an equivalent density of eight wells per section and at December 31, 2015, Niobrara PUD locations are booked at the equivalent density of 16 wells per section.

•

Strong environmental health and safety compliance programs. We have focused on establishing effective environmental health and safety programs that are able to earn trust and respect from regulatory agencies and public officials. We believe this is an important part of our strategy in competing in today’s intensive regulatory and public debate climate, and in working with the local communities in which we operate.

•

Community participation and outreach. We are dedicated to being an active and contributing member of the communities in which we operate. We share our success with these communities in various ways, including charitable giving and community event sponsorships. We also encourage our employees to take an active role through our charitable matching contribution fund and by participating in our “Energizing Our Community” day, during which our employees volunteer in the communities in which they work and live.

---

---

---

•

Crude oil. We do not refine any of our crude oil production. In the Wattenberg Field, crude oil is sold under various purchase contracts with monthly and longer term pricing provisions based on NYMEX pricing, adjusted for differentials. We have entered into longer term commitments ranging from three months to one year to deliver crude oil to competitive markets and these agreements have resulted in significantly improved deductions compared to earlier in 2015. We continue to pursue various alternatives with respect to oil transportation, particularly in the Wattenberg Field, with a view toward further improving pricing and limiting our use of trucking of production. We began delivering crude oil in accordance with our long term commitment to the White Cliffs Pipeline, LLC ("White Cliffs") pipeline in July 2015. This is one of several agreements we have entered into to facilitate deliveries of a portion of our crude oil to the Cushing, Oklahoma market. In addition, we have signed a long-term agreement for gathering of crude oil at the wellhead by pipeline from several of our pads in the Wattenberg Field, with a view toward minimizing truck traffic, increasing reliability and reducing the overall physical footprint of our well pads. We began delivering crude oil into this pipeline during the fourth quarter of 2015 and expect the system to be fully operational in the first quarter of 2016. In the Utica Shale, crude oil and condensate is sold to local purchasers at each individual well site based on NYMEX pricing, adjusted for differentials, and is typically transported by the purchasers via truck to local refineries, rail facilities or barge loading terminals on the Ohio River.

•

Natural gas. We primarily sell our natural gas to midstream service providers, marketers and utilities. Our natural gas is transported through third-party gathering systems and pipelines and we incur gathering, processing and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. We generally sell the natural gas that we produce in the Wattenberg Field under contracts with indexed, NYMEX or CIG monthly pricing provisions, with the remaining production sold under contracts with daily pricing provisions. Virtually all of our contracts include provisions whereby prices change with the market, with certain adjustments that may be made based on whether a well delivers to a gathering or transmission line and the quality of the natural gas. We have entered into firm gathering and processing agreements for all of our gas production to ensure there is infrastructure available to process the gas and get it to market. In the Wattenberg Field, the majority of our leasehold is dedicated to our primary midstream provider, DCP Midstream, LP, which gathers and processes wet natural gas produced in the basin and sells our residue gas to various markets. In the fourth quarter of 2014, we entered into an agreement with AKA Energy Group ("AKA") whereby we have committed production from a specified number of new horizontal wells to be drilled and completed by the end of 2016. Pursuant to the agreement, AKA is required to install and operate, or contract for use of, facilities necessary to receive and purchase the production volumes committed under the agreement. In the Utica Shale, wet natural gas produced in our northern acreage is gathered and processed pursuant to a firm gathering and processing agreement with MarkWest Utica EMG ("MarkWest") while wet natural gas produced in our southern acreage is gathered and processed by Blue Racer Midstream LLC ("Blue Racer"). The natural gas sales from the Blue Racer Plant are based on TETCO M-2 pricing. The gas sold at the tailgate of the MarkWest plant is sold at a price relative to the Chicago/Midwest market. Our sale of a significant portion of our Utica Shale gas to the Midwest market has helped to reduce the impact of the significant differentials that exist between the TETCO M-2 realizations and the NYMEX gas price. We anticipate that the significant Appalachian pipeline differentials that impact our Utica Shale natural gas, which make economics challenging, will continue well into 2016.

•

NGLs. In the Wattenberg Field, all of our NGLs are sold at the tailgate of the third-party midstream service provider processing plants based on a combination of prices from the Conway hub in Kansas and Mt. Belvieu in Texas where this production is marketed. In the Utica Shale, our NGLs are fractionated and marketed by MarkWest and Blue Racer and sold based on month-to-month pricing in various markets. Our NGL production is sold under both short- and long-term contracts. Due to an oversupply and growing inventories of nearly all domestic NGLs products, our realized sales price for NGLs declined significantly during 2015 and, while these prices have stabilized, we expect pricing to remain at depressed levels well into 2016 and perhaps beyond.

---

---

(1)	Amount represents undiscounted pre-tax future net cash flows estimated by Ryder Scott of approximately $2.8 billion, $7.3 billion and $6.4 billion as of December 31, 2015, 2014 and 2013, respectively, less an internally-estimated future income tax expense of approximately $0.5 billion, $2.3 billion and $2.1 billion, respectively.

(2)

PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure.

(3)	Includes estimated reserve data related to our Marcellus Shale crude oil and natural gas properties, which were divested in October 2014. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of these assets.

---

(1)	These prices are indices and do not include basin differentials for crude oil and natural gas. The above scenarios were calculated using the indicated index prices, less any basin differentials, transport fees, contractual adjustments and any Btu adjustments we experienced for the respective commodity.

(2)	The NYMEX prices used for the 2015 Reserve Report are based on SEC price parameters using the unweighted average of the prices in effect on the first day of the month for each month within the period of January 2015 through December 2015.

---

(1)	Includes drilling activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014.

(1)	Represents mechanical failures that resulted in the plugging and abandonment of the respective wells.

(2)	Includes activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014.

---

(1)	Includes activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014.

•	bond requirements in order to drill or operate wells;

•	well locations;

•	drilling and casing methods;

---

•	surface use and restoration of well properties;

•	well plugging and abandoning;

•	fluid disposal; and

•	air emissions.

•	costs of providing service, including depreciation expense;

•	allowed rate of return, including the equity component of the capital structure and related income taxes; and

•	volume throughput assumptions.

---

---

---

---

---

•	our revenue, profitability and cash flows;

•	our liquidity;

•	the quantity and present value of our reserves;

•	the borrowing base under our revolving credit facility and access to other sources of capital; and

•	the nature and scale of our operations.

•	relatively minor changes in regional, national or global supply and demand;

•	regional, national or global economic conditions, and perceived trends in those conditions;

•	geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries, or OPEC; and

•	regulatory changes.

•	fluctuations in prices of crude oil, natural gas and NGLs produced from the wells in the area;

•	natural disasters such as the flooding that occurred in the area in September 2013;

•	restrictive governmental regulations; and

•	curtailment of production or interruption in the availability of gathering, processing or transportation infrastructure and services, and any resulting delays or interruptions of production from existing or planned new wells.

---

---

---

---

---

---

•	our proved reserves;

•	the amount of crude oil, natural gas and NGLs we are able to produce from existing wells;

•	the prices at which crude oil, natural gas and NGLs are sold;

•	the costs to produce crude oil, natural gas and NGLs; and

•	our ability to acquire, locate and produce new reserves.

---

•	the economically recoverable quantities of crude oil, natural gas and NGLs attributable to any particular group of properties;

•	future depreciation, depletion and amortization (“DD&A”) rates and amounts;

•	impairments in the value of our assets;

•	the classifications of reserves based on risk of recovery;

•	estimates of future net cash flows;

•	timing of our capital expenditures; and

•	the amount of funds available for us to utilize under our revolving credit facility.

---

•	crude oil, natural gas and NGL prices;

•	the availability and cost of capital;

•	drilling and production costs;

•	availability of drilling services and equipment;

•	drilling results;

•	lease expirations;

•	midstream constraints;

•	access to and availability of water sourcing and distribution systems;

•	regulatory approvals; and

•	other factors.

•	unusual or unexpected geological formations;

•	pressures;

•	fires;

•	floods;

•	loss of well control;

•	loss of drilling fluid circulation;

•	title problems;

---

•	facility or equipment malfunctions;

•	unexpected operational events;

•	shortages or delays in the delivery of equipment and services;

•	unanticipated environmental liabilities;

•	compliance with environmental and other governmental requirements; and

•	adverse weather conditions.

---

•	incur additional debt;

•	pay dividends on, redeem or repurchase stock;

•	create liens;

•	make specified types of investments;

•	apply net proceeds from certain asset sales;

•	engage in transactions with our affiliates;

•	engage in sale and leaseback transactions;

•	merge or consolidate;

•	restrict dividends or other payments from restricted subsidiaries;

•	sell equity interests of restricted subsidiaries; and

•	sell, assign, transfer, lease, convey or dispose of assets.

---

---

---

•	The Dodd-Frank Act may limit our ability to enter into hedging transactions, thus exposing us to additional risks related to commodity price volatility; commodity price decreases would then have an increased adverse effect on our profitability and

---

•	If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy.

•	Our derivatives counterparties are, or will be, subject to significant new capital, margin and business conduct requirements imposed as a result of the Dodd-Frank Act. We expect that these requirements will increase the cost to hedge because there will be fewer counterparties in the market and increased counterparty costs will be passed on to us.

---

---

(1)	Purchases primarily represent shares purchased from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans.

---

---

(1)

Includes total proved reserves related to our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets of 40 MMBoe, 30 MMBoe and 22 MMBoe as of December 31, 2013, 2012 and 2011, respectively. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets.

(2)

Includes total proved reserves related to our Piceance Basin and North Eastern Colorado ("NECO") assets of 14 MMBoe and 59 MMBoe as of December 31, 2012 and 2011, respectively. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Piceance Basin and NECO assets.

(3)	Includes total proved reserves related to our Permian Basin assets of 11 MMBoe as of December 31, 2011. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian Basin assets.

---

•	Crude oil, natural gas and NGLs sales decreased to $378.7 million in 2015 compared to $471.4 million in 2014, due to a 51% decrease in the weighted-average realized prices of crude oil, natural gas and NGLs, offset in part by a 65% increase in production;

•	Negative net change in the fair value of unsettled derivative positions in 2015 was $35.8 million compared to a positive net change in the fair value of unsettled derivative positions of $311.1 million in 2014, primarily attributable to crude oil and natural gas derivatives that settled in 2015;

•	General and administrative expense decreased to $90.0 million in 2015 compared to $123.6 million in 2014, primarily attributable to $40.3 million recorded in 2014 in connection with certain partnership-related class action litigation and estimates relating to litigation arising from bankruptcy proceedings of certain affiliated partnerships;

•	Impairment of crude oil and natural gas properties was $161.6 million in 2015 compared to $166.8 million in 2014, both primarily related to the write-down of our Utica Shale producing and non-producing crude oil and natural gas properties; and

•	Depreciation, depletion and amortization expense increased to $303.3 million in 2015 compared to $192.5 million in 2014, primarily due to increased production, offset in part by lower weighted-average depreciation, depletion and amortization rates.

---

---

*	Percentage change is not meaningful or equal to or greater than 300%.

---

(1)	Production is net and determined by multiplying the gross production volume of properties in which we have an interest by our ownership percentage. For total production volume, including discontinued operations, see Part I, Item 6, Selected Financial Data.

(2)	One Bbl of crude oil or NGL equals six Mcf of natural gas.

(3)	Represents net settlements on derivatives related to crude oil and natural gas sales, which do not include net settlements on derivatives related to natural gas marketing.

(4)	Represents lease operating expenses, exclusive of production taxes, on a per unit basis.

(5)	Represents sales from natural gas marketing, net of costs of natural gas marketing, including net settlements and net change in fair value of unsettled derivatives related to natural gas marketing activities.

*	Percentage change is not meaningful or equal to or greater than 300%.

---

*	Percentage change is not meaningful or equal to or greater than 300%.

---

---

---

---

---

---

---

---

---

(1)	Table does not include deferred income tax liability to taxing authorities of $143.5 million, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.

(2)	Amount presented does not agree with the consolidated balance sheets in that it excludes $1.9 million of unamortized debt discount and $7.8 million of unamortized debt issuance costs. See Note 8, Long-Term Debt, to our consolidated financial statements included elsewhere in this report.

(3)	Represents our gross liability related to the fair value of derivative positions.

(4)	Short-term capital lease obligations are included in other accrued expenses on the consolidated balance sheets. Long-term capital lease obligations are included in other liabilities on the consolidated balance sheets.

(5)	Includes deferred compensation to former executive officers and deferred payments related to firm transportation agreements.

(6)

Table does not include an undrawn $11.7 million irrevocable standby letter of credit pending issuance to a transportation service provider. See Note 8, Long-Term Debt, to our consolidated financial statements included elsewhere in this report. Additionally, the table does not include the annual repurchase obligations to investing partners or termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. See Note 12, Commitments and Contingencies - Partnership Repurchase Provision; Employment Agreements with Executive Officers, to our consolidated financial statements included elsewhere in this report.

(7)

Amounts presented include $263.2 million to the holders of our 7.75% senior notes due 2022 and $1.4 million payable to the holders of our 3.25% convertible senior notes due 2016. Amounts also include $11.0 million payable to the participating banks in our revolving credit facility, of which interest of $6.6 million is related to unutilized commitments at a rate of 0.38% per annum, $4.3 million related to the outstanding borrowings on our revolving credit facility of $37.0 million and $0.2 million related to our undrawn letters of credit.

(8)	Represents our gross commitment. See Note 12, Commitments and Contingencies - Firm Transportation, Processing and Sales Agreements, to our consolidated financial statements included elsewhere in this report.

---

---

---

•	operating performance and return on capital as compared to our peers;

•	financial performance of our assets and our valuation without regard to financing methods, capital structure or historical cost basis;

•	ability to generate sufficient cash to service our debt obligations; and

•	viability of acquisition opportunities and capital expenditure projects, including the related rate of return.

---

---

(1)	A standard unit of measurement for natural gas (one BBtu equals one MMcf).

(2)	Approximately 34.3% of the fair value of our derivative assets were measured using significant unobservable inputs (Level 3). See Note 3, Fair Value Measurements, to the consolidated financial statements included elsewhere in this report.

---

---

---

---

---

---

---

---

•	Production-related general and administrative costs totaling $7.7 million and $3.8 million for 2014 and 2013, respectively, have been reclassified from production costs to general and administrative expense;

•	Prepaid well costs write-offs totaling $3.3 million and $0.4 million for 2014 and 2013, respectively, have been reclassified from production costs to impairment of crude oil and natural gas properties; and

•	Prepaid well costs totaling $27.3 million in the December 31, 2014 consolidated balance sheet have been reclassified from other assets to properties and equipment, net;

•	Debt issuance costs totaling $9.4 million in the December 31, 2014 consolidated balance sheet have been reclassified from other assets and are presented as a direct deduction from the carrying amount of long-term debt; and

•	Current deferred income tax liabilities totaling $59.2 million in the December 31, 2014 consolidated balance sheet have been reclassified to non-current pursuant to the income tax accounting standards update issued and adopted in 2015.

---

---

---

---

---

---

---

•	For crude oil and natural gas sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market; and

•	For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative.

•

Collars contain a fixed floor price and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty;

•

Swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty;

•

Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG-basis protection swaps, which had a negative differential to NYMEX for the majority of 2015, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty; and

•	Physical sales and purchases are derivatives for fixed-priced physical transactions where we sell or purchase third-party supply at fixed rates. These physical derivatives are offset by financial swaps: for a physical sale the offset is a swap purchase and for a physical purchase the offset is a swap sale.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

*	These prices are based on the index prices and are net of basin differentials, any transport fees, contractual adjustments and any Btu adjustments we experienced for the respective commodity.

---

(1)

Includes estimated reserve data related to our Piceance and NECO assets, which were divested in June 2013. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Piceance and NECO assets. Total proved reserves include 148 MBbls of crude oil and 83,656 MMcf of natural gas, for an aggregate of 14,091 MBoe of crude oil equivalent related to our Piceance and NECO assets. There were no proved undeveloped reserves attributable to the Piceance and NECO assets as of December 31, 2012.

(2)

Includes estimated reserve data related to our Marcellus Shale assets, which were divested in October 2014. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Marcellus Shale assets. Total proved reserves included 235,950 MMcf of natural gas, for an aggregate of 39,325 Mboe of crude oil equivalent, related to our Marcellus Shale assets. Total proved developed reserves related to those assets included 53,904 MMcf and 8,984 MBoe, respectively, and proved undeveloped reserves included 182,046 MMcf and 30,341 MBoe, respectively.

---

---

---

(1)	Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property.

(2)

Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2015, 2014 and 2013, $207.8 million, $125.2 million and $40.1 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end.

(3)	Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs.

---

*	Represents future estimated lease operating expenses, production taxes, transportation, gathering and processing expenses and plugging and abandonment costs, net of salvage value.

---

(1)

Our weighted-average price, net of production costs per Boe, in our 2015 reserve report decreased to $17.30 as compared to $37.78 in our 2014 reserve report. This is due to the significant decrease in SEC commodity prices utilized in the 2015 reserve report. Our weighted-average price, net of production costs per Boe, in our 2014 reserve report increased to $37.78 from $30.82 in our 2013 reserve report. This is due to the divestiture of our Marcellus Shale reserves during 2014 which further increased our liquids as a percentage of proved reserves.

(2)

The 66% decrease in 2015 indicates a significant decrease in the value of the extensions in 2015 as compared to the value of the extensions in 2014. This is primarily due to lower SEC commodity prices utilized in the 2015 reserve report. The 6% decrease in 2014 as compared to 2013 is primarily due to a scheduled maximum rig count of six rigs by 2016 as compared to a scheduled maximum rig count of seven in the 2013 year-end reserve report, partially offset by our increased PUD count in the Wattenberg Field resulting from successful downspacing tests in 2014.

(3)	The decrease in sales of reserves in 2015 was due to the fact that no major divestitures were completed in 2015. The increase in sales of reserves in 2014 as compared to 2013 was due to the divestiture of our Marcellus shale assets in October 2014.

(4)	The decrease in purchases of reserves in 2015 and 2014 as compared to the respective prior years was due to no material acquisitions having occurred.

(5)	The change in revisions of our previous quantity estimates in 2015 as compared to 2014 was primarily due to adjustments due to our drilling schedule. The change in revisions of our previous quantity estimates in 2014 as compared to 2013 was primarily due to adjustments due to our drilling schedule.

(6)

The change in estimated income taxes for each year as compared to the prior year is the direct result of the significant changes in discounted future net cash flows, as the projected deferred tax rate remained relatively unchanged at approximately 38% for each of the three years ended December 31, 2015, 2014 and 2013. In addition, the Company continued to capitalize and amortize the majority of its yearly capital expenditures and there were no changes in the assumptions as to the tax deductibility of beginning unamortized capital, additional current year capital or future development capital. Further, future tax deductions for capital expenditures were not affected by the impairment of crude oil and natural gas properties in 2014 and 2015 as such impairments are not tax deductible.

---

---

(1)	For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For valuation allowance for unproved crude oil and natural gas properties, deductions represent accumulated amortization of expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset.

---

---

---

---

---

---

---

---