General

We are an independent crude oil and natural gas company with properties in the North, South and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend Anadarko Canadian Kingfisher) areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations.

We were formed in 1967 to explore for, develop and produce crude oil and natural gas properties. Through the 1980s, our activities and growth remained focused primarily in Oklahoma. In the 1980s, we expanded our activity into the North region. The North region comprised approximately 59% of our crude oil and natural gas production and approximately 69% of our crude oil and natural gas revenues for the year ended December 31, 2017 . The Company’s principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. Approximately 50% of our estimated proved reserves as of December 31, 2017 are located in the North region. In recent years, we have significantly expanded our operations in our South region with our increased activity in the SCOOP and STACK plays. The South region comprised approximately 41% of our crude oil and natural gas production, 31% of our crude oil and natural gas revenues, and 50% of our estimated proved reserves as of and for the year ended December 31, 2017 .

We focus our exploration activities in large new or developing crude oil and natural gas plays that provide us the opportunity to acquire undeveloped acreage positions for future drilling operations. We have been successful in targeting large repeatable resource plays where three dimensional seismic, horizontal drilling, geosteering technologies, advanced completion technologies (e.g., fracture stimulation) and enhanced recovery technologies allow us to develop and produce crude oil and natural gas reserves from unconventional formations. As a result of these efforts, we have grown substantially through the drill bit.

As of December 31, 2017 , our estimated proved reserves were 1,331 MMBoe, with estimated proved developed reserves of 602 MMBoe, or 45% of our total estimated proved reserves. Crude oil represents approximately 48% of our estimated proved reserves as of December 31, 2017 . The standardized measure of our discounted future net cash flows totaled approximately $10.5 billion at December 31, 2017 .

For 2017 , we generated crude oil and natural gas revenues of $ 2.98 billion and operating cash flows of $2.08 billion . Crude oil accounted for approximately 57% of our total production and approximately 78% of our crude oil and natural gas revenues for 2017 . Production averaged 242,637 Boe per day for 2017 , a 12% increase compared to average production of 216,912 Boe per day for 2016 . Average daily production for the quarter ended December 31, 2017 increased 37% to 286,985 Boe per day compared to 209,861 Boe per day for the quarter ended December 31, 2016 due to increased drilling and completion activities.

The table below summarizes our total estimated proved reserves, PV-10 (non-GAAP) and net producing wells as of December 31, 2017 , average daily production for the quarter ended December 31, 2017 and the reserve-to-production index in our principal operating areas. The PV-10 values shown below are not intended to represent the fair market value of our crude oil and natural gas properties. There are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves. See Part I, Item 1A. Risk Factors and “Critical Accounting Policies and Estimates” in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this report for further discussion of uncertainties inherent in the reserve estimates.  

 

Business Environment and Outlook

Our industry has been significantly impacted by lower commodity prices in recent years. The downward pressure on prices experienced in 2015 and 2016 showed signs of easing in 2017. Commodity prices remained volatile during the year, but generally increased on average in 2017 relative to 2016 in response to improving domestic and global supply and demand fundamentals and other factors. Crude oil prices in particular showed significant signs of improvement in late 2017 and early 2018, with West Texas Intermediate crude oil benchmark prices reaching a three-year high of $66 per barrel in January 2018. Crude oil prices remain volatile and it is uncertain whether the increase in market prices experienced in recent months will be sustained.

Continental marked its 50th anniversary in the oil and gas business in 2017. Our leadership team has significant experience with operating in challenging commodity price environments. With our portfolio of high quality assets, we are well-positioned to manage the ongoing challenges and price volatility facing our industry.

For 2018, our primary business strategies will focus on:

Based on an expectation for higher operating cash flows in 2018 in response to improvement in crude oil prices in late 2017 and early 2018, we have increased our planned non-acquisition capital spending for 2018 to $2.3 billion compared to $2.0 billion spent in 2017, with approximately 78% of our 2018 drilling and completion budget focusing on oil-weighted areas in

the North Dakota Bakken and SCOOP Springer plays. We expect to fund our budgeted spending using cash flows from operations. We may adjust our pace of drilling and development as 2018 market conditions evolve.

For 2018 , we plan to operate an average of approximately 21 drilling rigs and 10 completion crews for the year. We expect to spend approximately 52% of our 2018 capital expenditures budget on drilling and completion activities in North Dakota Bakken, 20% in SCOOP, and 14% in STACK. The remaining 14% of our 2018 budget will target other capital expenditures such as leasing and renewals, work-overs, and facilities. See the section below titled Summary of Crude Oil and Natural Gas Properties and Projects for further discussion of our 2018 plans.

Our Business Strategy

Despite ongoing volatility and uncertainty in commodity prices, our business strategy continues to be focused on increasing shareholder value by finding and developing crude oil and natural gas reserves at costs that provide attractive rates of return. The principal elements of this strategy include:

Growing and sustaining a premier portfolio of assets focused on balancing production growth with free cash flow generation. We hold a portfolio of leasehold acreage, drilling opportunities and uncompleted wells in certain premier U.S. resource plays with varying access to crude oil, natural gas, and natural gas liquids. We pursue opportunities to develop our existing properties as well as explore for new resource plays where significant reserves may be economically developed. Our capital programs are designed to allocate investments to projects that provide opportunities to deliver strong production growth while generating cash flows in excess of operating and capital requirements, to work down our large inventory of uncompleted wells, to convert our undeveloped acreage to acreage held by production, and to improve hydrocarbon recoveries and rates of return on capital employed. While our operations have historically focused on the exploration and development of crude oil, we also allocate significant capital to natural gas areas that provide attractive rates of return.

Enhance cash flows and return on capital employed through costs reductions, operating efficiencies, technical innovations, and optimized completions. We continue to manage through the current commodity price environment by focusing on improving operating efficiencies and reducing costs. Our key operating areas are characterized by large acreage positions in select unconventional resource plays with multiple stacked geologic formations that provide repeatable drilling opportunities and resource potential. We operate a significant portion of our wells and leasehold acreage and believe the concentration of our operated assets allows us to leverage our technical expertise and manage the development of our properties to achieve cost reductions through operating efficiencies and economies of scale.

We continued to achieve efficiency gains in various aspects of our business in 2017, including additional reductions in spud-to-total depth drilling times and average days to drill horizontal laterals, which has led to reductions in drilling costs in our core areas. In addition to lowering our drilling costs, we also work to enhance cash flows through the use of optimized completion technologies that help improve recoveries and rates of return. These efforts have had a positive impact on the efficiency of our capital deployed in recent years, resulting in significant improvement in the quantity of reserves found and developed per dollar invested.

Maintaining financial flexibility and a strong balance sheet . Maintaining a strong balance sheet, ample liquidity, and financial flexibility are key components of our business strategy. In 2017, we reduced our total debt by $226 million , or 3% , from $6.58 billion at year-end 2016 to $6.35 billion at year-end 2017. We are actively targeting further debt reduction using available cash flows from operations or proceeds from potential sales of non-strategic assets and joint development opportunities and will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry.

Focusing on organic growth through disciplined capital investments . Although we consider various growth opportunities, including property acquisitions, our primary focus is on organic growth through leasing and drilling in our core areas where we can exploit our extensive inventory of repeatable drilling opportunities to achieve attractive rates of return. From January 1, 2015 through December 31, 2017 , our proved reserve additions through extensions and discoveries were 743 MMBoe compared with insignificant proved reserve acquisitions during that same period.

Our Business Strengths

We have a number of strengths we believe will help us successfully execute our business strategy, including the following:

Large Acreage Inventory . We held approximately 598,400 net undeveloped acres and 1.19 million net developed acres under lease as of December 31, 2017 concentrated in certain premier U.S. resource plays. We are among the largest leaseholders in the Bakken, SCOOP and STACK plays. Being an early entrant in these plays has allowed us to capture significant acreage positions in core parts of the plays.

Expertise with Horizontal Drilling and Optimized Completion Methods . We have substantial experience with horizontal drilling and optimized completion methods and continue to be among industry leaders in the use of new drilling and completion technologies. We continue to improve drilling and completion efficiencies through the use of multi-well pad drilling in our operating areas. Further, we are among industry leaders in drilling long lateral lengths. We have also been among industry leaders in testing and utilizing optimized completion technologies involving various combinations of fluid types, proppant types and volumes, and stimulation stage spacing to determine optimal methods for improving recoveries and rates of return. We continually refine our drilling and completion techniques in an effort to deliver improved results across our properties.

Control Operations Over a Substantial Portion of Our Assets and Investments . As of December 31, 2017 , we operated properties comprising 89% of our total proved reserves. By controlling a significant portion of our operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and completion methods used.

Experienced Management Team . Our senior management team has extensive expertise in the oil and gas industry. Our Chief Executive Officer, Harold G. Hamm, began his career in the oil and gas industry in 1967. Our 9 senior officers have an average of 38 years of oil and gas industry experience.

Financial Position and Liquidity . Currently we have a revolving credit facility with lender commitments totaling $2.75 billion that matures in May 2019. We had approximately $2.65 billion of available borrowing capacity under our credit facility at January 31, 2018 after considering outstanding borrowings and letters of credit.

Our credit facility is unsecured and does not have a borrowing base requirement that is subject to periodic redetermination based on changes in commodity prices and proved reserves. Additionally, downgrades or other negative rating actions with respect to our credit rating do not trigger a reduction in our current credit facility commitments, nor do such actions trigger a security requirement or change in covenants. Downgrades of our credit rating will, however, trigger increases in our credit facility’s interest rates and commitment fees paid on unused borrowing availability under certain circumstances.

Crude Oil and Natural Gas Operations

Proved Reserves

Proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain. In connection with the estimation of proved reserves, the term “reasonable certainty” implies a high degree of confidence that the quantities of crude oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal reserve engineers and Ryder Scott Company, L.P (“Ryder Scott”), our independent reserve engineers, employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps including isopach and structure maps, analogy and statistical analysis, and available downhole, production, seismic, and well test data.

The following table sets forth estimated proved crude oil and natural gas reserves information by reserve category as of December 31, 2017 . The standardized measure of our discounted future net cash flows totaled approximately $10.5 billion at December 31, 2017 . Our reserve estimates as of December 31, 2017 are based primarily on a reserve report prepared by Ryder Scott. In preparing its report, Ryder Scott evaluated properties representing approximately 96% of our PV-10 and 96% of our total proved reserves as of December 31, 2017 . Our internal technical staff evaluated the remaining properties. A copy of Ryder Scott’s summary report is included as an exhibit to this Annual Report on Form 10-K.  

Our estimated proved reserves and related future net revenues, Standardized Measure and PV-10 at December 31, 2017 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2017 through December 2017 , without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $51.34 per Bbl for crude oil and $2.98 per MMBtu for natural gas ( $47.03 per Bbl for crude oil and $3.00 per Mcf for natural gas adjusted for location and quality differentials).

 

The following table provides additional information regarding our estimated proved crude oil and natural gas reserves by region as of December 31, 2017 .  

The following table provides information regarding changes in total estimated proved reserves for the periods presented.  

Revisions of previous estimates.  Revisions represent changes in previous reserve estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices and differentials, operating costs, or development costs.

Given the significant volatility in commodity prices in recent years, and given the uncertainty regarding the timing, magnitude and duration of any price recovery, maintaining a strong balance sheet, ample liquidity, and financial flexibility has become an increasingly important component of our long-term business strategy. In light of our strategy to preserve financial flexibility and minimize the incurrence of new debt, we maintained a disciplined spending approach in 2017 and continued to refine our capital program to focus on areas that provide the greatest opportunities to achieve operating efficiencies and cost reductions, to convert undeveloped acreage to acreage held by production, and to improve hydrocarbon recoveries, cash flows and rates of return using optimized completions. As part of this effort, we shifted a portion of our 2017 spending away from the SCOOP and Bakken plays to areas in the emerging STACK play that offered more advantageous opportunities and rates of return in the 2017 commodity price environment. This shift in strategy coupled with our increased emphasis on balancing capital spending with cash flows altered the timing and extent of our previous development plans in certain areas and resulted in the removal of 41 MMBo and 290 Bcf (totaling 89 MMBoe) of PUD reserves no longer scheduled to be developed within five years from the date of initial booking. These removals do not represent the elimination of recoverable hydrocarbons physically in place. In some instances the removed reserves may be developed in the future in the event of further improvement in commodity prices and an expansion of our capital expenditure budget.

Commodity prices increased on average in 2017 relative to 2016 in response to improving domestic and global supply and demand fundamentals and other factors. The 12-month average first-day-of-the-month price for crude oil increased 20% from $42.75 per Bbl for 2016 to $51.34 per Bbl for 2017 , while the 12-month average first-day-of-the-month price for natural gas increased 20% from $2.49 per MMBtu for 2016 to $2.98 per MMBtu for 2017 . These changes increased the economic lives of

certain producing properties and caused certain previously uneconomic projects to become economic, which had a favorable impact on the Company’s proved reserve estimates, resulting in upward revisions of 29 MMBo and 78 Bcf (totaling 42 MMBoe) in 2017 .

Additionally, changes in anticipated production performance on certain properties resulted in 59 MMBo of downward revisions to crude oil reserves and 173 Bcf of upward revisions to natural gas reserves (netting to 30 MMBoe of downward revisions) in 2017 . Further, changes in ownership interests, operating costs, and other factors during the year resulted in 7 MMBo of downward revisions to crude oil reserves and 11 Bcf of upward revisions to natural gas reserves (netting to 5 MMBoe of downward revisions) in 2017 .

Extensions, discoveries and other additions.  These are additions to our proved reserves that result from (i) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (ii) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions for each of the three years reflected in the table above were primarily due to increases in proved reserves associated with our successful drilling and completion activities in the Bakken, SCOOP and STACK areas. Proved reserve additions from our drilling activities in the Bakken totaled 148 MMBoe, 73 MMBoe and 96 MMBoe for 2017 , 2016 and 2015 , respectively, while reserve additions in SCOOP totaled 53 MMBoe, 97 MMBoe and 93 MMBoe for 2017 , 2016 and 2015 , respectively. Additionally, extensions and discoveries were impacted by successful drilling and completion results in the STACK play, resulting in proved reserve additions of 39 MMBoe, 79 MMBoe and 57 MMBoe in 2017 , 2016 and 2015 , respectively. See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2017 drilling activities. We expect a significant portion of future reserve additions will continue to come from our major development projects in the Bakken, SCOOP and STACK areas.

Sales of minerals in place. These are reductions to proved reserves resulting from the disposition of properties during a period. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 14. Property Dispositions for further discussion of notable dispositions. We may continue to seek opportunities to sell non-strategic properties if and when we have the ability to dispose of such assets at favorable terms.

Purchases of minerals in place.  These are additions to proved reserves resulting from the acquisition of properties during a period. We have had no significant acquisitions in the past three years. However, we may participate as a buyer of properties when and if we have the ability to increase our position in strategic plays at favorable terms.

Proved Undeveloped Reserves

All of our PUD reserves at December 31, 2017 are located in the Bakken, SCOOP, and STACK plays, our most active development areas, with those plays comprising 43%, 45%, and 12%, respectively, of our total PUD reserves at year-end 2017 . The following table provides information regarding changes in our PUD reserves for the year ended December 31, 2017 . Our PUD reserves at December 31, 2017 include 70 MMBoe of reserves associated with wells where drilling has occurred but the wells have not been completed or are completed but not producing ("DUC wells"). Our DUC wells are classified as PUD reserves when relatively major expenditures are required to complete and produce from the wells.

		Crude Oil (MBbls)			Natural Gas (MMcf)			Total (MBoe)
Proved undeveloped reserves at December 31, 2016		353,018			2,419,198			756,218
Revisions of previous estimates		(73,684	)		(131,306	)		(95,569	)
Extensions and discoveries		100,874			492,468			182,952
Sales of minerals in place		(3,441	)		(24,870	)		(7,586	)
Purchases of minerals in place		149			3,009			650
Conversion to proved developed reserves		(54,674	)		(317,379	)		(107,571	)
Proved undeveloped reserves at December 31, 2017		322,242			2,441,120			729,094

Revisions of previous estimates.  During the year ended December 31, 2017 , we removed 165 gross (123 net) PUD locations, which resulted in the removal of 41 MMBo and 290 Bcf (totaling 89 MMBoe) of PUD reserves, of which 31 MMBo and 66 Bcf (totaling 42 MMBoe) was related to our Bakken properties and 10 MMBo and 218 Bcf (totaling 46 MMBoe) was related to our SCOOP properties. These removals were due to the aforementioned refinement of our drilling program to place emphasis on areas that provide the greatest opportunities to achieve operating efficiencies and cost reductions, to convert undeveloped acreage to acreage held by production, and to improve hydrocarbon recoveries, cash flows and rates of return using optimized completions. These and other aforementioned factors altered the timing and extent of our previous development plans in certain

areas and resulted in the removal of PUD reserves no longer scheduled to be developed within five years of the date of initial booking.

Additionally, increases in average crude oil and natural gas prices in 2017 caused certain previously uneconomic projects to become economic, which resulted in upward PUD reserve revisions of 8 MMBo and 22 Bcf (totaling 11 MMBoe) in 2017 . Further, changes in anticipated production performance on producing properties having offsetting PUD locations resulted in 43 MMBo of downward revisions to crude oil PUD reserves and 134 Bcf of upward revisions to natural gas PUD reserves (netting to 20 MMBoe of downward revisions) in 2017 . Finally, changes in ownership interests, operating costs, and other factors during the year resulted in 3 MMBo of upward revisions to crude oil PUD reserves and 3 Bcf of upward revisions to natural gas PUD reserves (totaling 3 MMBoe of upward revisions) in 2017 .

Extensions and discoveries.  Extensions and discoveries were primarily due to increases in PUD reserves associated with our successful drilling activity in the Bakken, SCOOP and STACK areas. PUD reserve additions in the Bakken totaled 86 MMBo and 216 Bcf (totaling 122 MMBoe) in 2017 , while SCOOP PUD reserve additions totaled 13 MMBo and 193 Bcf (totaling 45 MMBoe), and STACK PUD reserve additions totaled 2 MMBo and 83 Bcf (totaling 16 MMBoe). See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2017 drilling activities in these areas.

Conversion to proved developed reserves. In 2017 , we developed approximately 17% of our PUD locations and 14% of our PUD reserves booked as of December 31, 2016 through the drilling and completion of 300 gross (146 net) development wells at a capital cost of approximately $762 million incurred in 2017. PUD conversions in North Dakota Bakken totaled 49 MMBo and 106 Bcf (totaling 66 MMBoe) in 2017 , while STACK PUD conversions totaled 4 MMBo and 130 Bcf (totaling 26 MMBoe) and SCOOP PUD conversions totaled 2 MMBo and 81 Bcf (totaling 15 MMBoe).

Given the continued volatility in crude oil prices during the year, we chose not to significantly advance the development of our oil-weighted properties in the SCOOP play in 2017, instead choosing to defer development capital in that play to future periods when prices become more stable and sustainable. Additionally, we deferred certain well completion activities in North Dakota Bakken in 2017 and our inventory of DUC wells that built up in that play in 2016 was not reduced to the extent originally planned for the year. These factors adversely impacted our conversion of PUD reserves to proved developed reserves in 2017.

At December 31, 2016 , we had 95 MMBoe of PUD reserves associated with 279 gross (145 net) operated and non-operated DUC locations at that date. A portion of those locations, representing 18 MMBoe of PUD reserves, were not completed in 2017 and are not reflected as having been converted to proved developed reserves during the year and continue to be reflected as PUD locations at December 31, 2017 . If the year-end 2016 DUC wells had been fully completed and converted to proved developed locations in 2017, our 2017 PUD reserve conversion rate of 14% would have been 17%.

Our inventory of DUC wells classified as PUDs total 278 gross (105 net) operated and non-operated locations at December 31, 2017 , representing 70 MMBoe, or 10%, of our PUD reserves. The following table summarizes 2017 activity associated with DUC wells that are classified as PUD reserves.

		DUC Wells
		Gross			Net			PUD Reserves (MBoe)
DUC wells at December 31, 2016		279			145			95,272
Wells converted to proved developed reserves		(203	)		(110	)		(75,274	)
Wells added		209			72			51,306
Revisions		(7	)		(2	)		(1,707	)
DUC wells at December 31, 2017		278			105			69,597

Development plans. We have acquired substantial leasehold positions in the Bakken, SCOOP and STACK plays. Our drilling programs to date in those areas have focused on proving our undeveloped leasehold acreage through strategic drilling, thereby increasing the amount of leasehold acreage in the secondary term of the lease with no further drilling obligations (i.e., categorized as held by production) and resulting in a reduced amount of leasehold acreage in the primary term of the lease. While we may opportunistically drill strategic exploratory wells, a substantial portion of our future capital expenditures will be focused on developing our PUD locations, including our drilled but not completed locations. The costs to drill our uncompleted wells were incurred prior to December 31, 2017 and only the remaining completion costs are included in future development plans.

Estimated future development costs relating to the development of PUD reserves are projected to be approximately $1.0 billion in 2018 (44% of total capital budget), $1.5 billion in 2019 , $1.7 billion in 2020 , $1.5 billion in 2021 , and $0.7 billion in 2022 . These capital expenditure projections are reflective of the current commodity price environment and have been established based on an expectation of drilling and completion costs, available cash flows, and borrowing capacity. Development of our existing PUD reserves at December 31, 2017 , including those associated with DUC wells, is expected to occur within five years of the date of initial booking of the PUDs. PUD reserves not expected to be developed within five years of initial booking because of changes in business strategy, depressed commodity prices, or for other reasons have been removed from our reserves at December 31, 2017 . We had no PUD reserves at December 31, 2017 that remain undeveloped beyond five years from the date of initial booking.

Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process

Ryder Scott, our independent reserves evaluation consulting firm, estimated, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC, 96% of our PV-10 and 96% of our total proved reserves as of December 31, 2017 included in this Form 10-K. The Ryder Scott technical personnel responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Refer to Exhibit 99 included with this Form 10-K for further discussion of the qualifications of Ryder Scott personnel.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserves engineers to ensure the integrity, accuracy and timeliness of data furnished to Ryder Scott in their reserves estimation process. Our technical team is in contact regularly with representatives of Ryder Scott to review properties and discuss methods and assumptions used in Ryder Scott’s preparation of the year-end reserves estimates. Proved reserves information is reviewed by our Audit Committee with representatives of Ryder Scott and by our internal technical staff before the information is filed with the SEC on Form 10-K. Additionally, certain members of our senior management review and approve the Ryder Scott reserves report and on a semi-annual basis review any internal proved reserves estimates.

Our Vice President—Corporate Reserves is the technical person primarily responsible for overseeing the preparation of our reserve estimates. He has a Bachelor of Science degree in Petroleum Engineering, an MBA in Finance and 33 years of industry experience with positions of increasing responsibility in operations, acquisitions, engineering and evaluations. He has worked in the area of reserves and reservoir engineering most of his career and is a member of the Society of Petroleum Engineers. The Vice President—Corporate Reserves reports directly to our Vice Chairman of Strategic Growth Initiatives. The reserves estimates are reviewed and approved by the Company's President and certain other members of senior management.

Proved Reserve, Standardized Measure, and PV-10 Sensitivities

Our year-end 2017 proved reserve, Standardized Measure, and PV-10 estimates were prepared using 2017 average first-day-of-the-month prices of $51.34 per Bbl for crude oil and $2.98 per MMBtu for natural gas ( $47.03 per Bbl for crude oil and $3.00 per Mcf for natural gas adjusted for location and quality differentials). Actual future prices may be materially higher or lower than those used in our year-end estimates.

Provided below are sensitivities illustrating the potential impact on our estimated proved reserves, Standardized Measure, and PV-10 at December 31, 2017 under different commodity price scenarios for crude oil and natural gas. In these sensitivities, all factors other than the commodity price assumption have been held constant for each well. These sensitivities demonstrate the impact that changing commodity prices may have on estimated proved reserves, Standardized Measure, and PV-10 and there is no assurance these outcomes will be realized.

The crude oil price sensitivities provided below show the impact on proved reserves, Standardized Measure, and PV-10 under various crude oil price scenarios, with natural gas prices being held constant at the 2017 average first-day-of-the-month price of $2.98 per MMBtu.

The natural gas price sensitivities provided below show the impact on proved reserves, Standardized Measure, and PV-10 under various natural gas price scenarios, with crude oil prices being held constant at the 2017 average first-day-of-the-month price of $51.34 per Bbl.

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2017 scheduled to expire over the next three years by region unless production is established within the spacing units covering the acreage prior to the expiration dates or the leases are renewed.  

As of December 31, 2017 , there were 475 gross (179 net) operated and non-operated wells that have been spud and are in the process of drilling, completing or waiting on completion.

Summary of Crude Oil and Natural Gas Properties and Projects

In the following discussion, we review our budgeted number of wells and capital expenditures for 2018 in our key operating areas. Our 2018 capital budget has been set based on an expectation of available cash flows in order to minimize the incurrence of new debt. If cash flows are materially impacted by a decline in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability of our revolving credit facility if needed to fund our operations. Conversely, higher cash flows resulting from an increase in commodity prices could result in increased capital expenditures.

The following table provides information regarding well counts and 2018 budgeted capital expenditures by operating area.

		2018 Plan
		Gross wells (1)			Net wells (1)			Capital expenditures  (in millions) (2)
North Region:
Bakken		415			143			$	1,193
South Region:
SCOOP		160			44			465
STACK and Other		181			38			330
Total exploration and development drilling		756			225			$	1,988
Land								132
Capital facilities, workovers and other corporate assets								168
Seismic								12
Total 2018 capital budget, excluding acquisitions								$	2,300

(1) Represents operated and non-operated wells expected to have first production in 2018.

(2) Represents total capital expenditures for operated and non-operated wells expected to have first production in 2018 and wells spud that will be in the process of drilling, completing or waiting on completion as of year-end 2018.

North Region

Our properties in the North region represented 50% of our total proved reserves as of December 31, 2017 and 61% of our average daily Boe production for the fourth quarter of 2017 . Our average daily production from such properties was 175,563 Boe per day for the fourth quarter of 2017 , an increase of 48% from the comparable 2016 period due to increased drilling and completion activities in 2017. Our principal producing properties in the North region are primarily located in the Bakken field.

Bakken Field

The Bakken field of North Dakota and Montana is one of the premier crude oil resource plays in the United States. We are a leading producer, leasehold owner and operator in the Bakken. As of December 31, 2017 , we controlled one of the largest leasehold positions in the Bakken with approximately 1.3 million gross ( 801,500 net) acres under lease.

Our total Bakken production averaged 165,598 Boe per day for the fourth quarter of 2017 , up 58% from the 2016 fourth quarter. For the year ended December 31, 2017 , our average daily Bakken production increased 12% over 2016 . We increased our drilling and well completion activities in the Bakken in 2017, particularly in the second half of the year, in response to stabilization and improvement in crude oil prices. In 2017 , we participated in the drilling and completion of 370 gross (145 net) wells in the Bakken compared to 192 gross (38 net) wells completed in 2016. Our 2017 activities in the Bakken focused on development of de-risked, higher rate-of-return areas in core parts of North Dakota and the testing of various optimized completion methods aimed at improving crude oil recoveries and rates of return.

Our Bakken properties represented 48% of our total proved reserves at December 31, 2017 and 58% of our average daily Boe production for the 2017 fourth quarter. Our total proved Bakken field reserves as of December 31, 2017 were 636 MMBoe, an increase of 7% compared to December 31, 2016 due to reserves added from our drilling program, continued improvement in recoveries driven by advances in optimized completion designs, and upward reserve revisions prompted by higher commodity prices in 2017. Our inventory of proved undeveloped drilling locations in the Bakken totaled 1,252 gross (656 net) wells as of December 31, 2017 .

In response to the stabilization and improvement in crude oil prices in late 2017 and early 2018 we plan to increase our activities in North Dakota Bakken in 2018 relative to 2017. In 2018 , we plan to invest approximately $1.19 billion in the play, which includes $413 million for the completion and initiation of production on operated Bakken wells that were drilled but not completed as of year-end 2017. We plan to operate, on average, six rigs in North Dakota Bakken throughout 2018 , an increase from four rigs as of December 31, 2017 . Additionally, we plan to use, on average, six to seven well completion crews in North Dakota Bakken throughout 2018 , consistent with our current activity levels. Our 2018 drilling and completion activities will focus on core parts of North Dakota Bakken that provide opportunities to improve capital efficiency, reduce finding and development costs, and improve recoveries and rates of return.

South Region

Our properties in the South region represented 50% of our total proved reserves as of December 31, 2017 and 39% of our average daily Boe production for the fourth quarter of 2017 . For the 2017 fourth quarter, our average daily production from such properties was 111,422 Boe per day, an increase of 22% from the comparable period in 2016 . Our principal producing properties in the South region are located in the SCOOP and STACK areas of Oklahoma.

SCOOP

The SCOOP play currently extends across Garvin, Grady, Stephens, Carter, McClain and Love counties in Oklahoma and contains crude oil and condensate-rich fairways as delineated by numerous industry wells. We are a leading producer, leasehold owner and operator in the SCOOP play. As of December 31, 2017 , we controlled one of the largest leasehold positions in SCOOP with approximately 491,100 gross ( 276,900 net) acres under lease.

Our SCOOP leasehold has the potential to contain hydrocarbons from a variety of conventional and unconventional reservoirs overlying and underlying the Woodford formation in Oklahoma. In recent years, our drilling activities have resulted in the vertical expansion of our SCOOP Woodford position with discoveries of the SCOOP Springer and Sycamore formations, which are located directly above the Woodford formation. Located in the heart of our SCOOP acreage, our Springer and Sycamore positions supplement our Woodford leasehold and expand our resource potential and inventory in the play. 

We engaged in limited drilling and completion activities in SCOOP in 2017, choosing instead to allocate capital to other areas that offered more advantageous opportunities and rates of return. Our 2017 activities in SCOOP focused on continued vertical and horizontal expansion of the productive extent and hydrocarbon content of the play and working to determine optimum well spacing, well patterns, and completion methods for future development.

SCOOP represented 37% of our total proved reserves as of December 31, 2017 and 22% of our average daily Boe production for the fourth quarter of 2017 . Production in SCOOP averaged 62,242 Boe per day during the fourth quarter of 2017 , down 2% compared to the 2016 fourth quarter. For the year ended December 31, 2017 , average daily production in SCOOP decreased 7% compared to 2016 , reflecting natural declines in production and limited drilling and completion activities in 2017. We participated in the drilling and completion of 77 gross (20 net) wells in SCOOP during 2017 compared to 72 gross (28 net) wells in 2016 . Proved reserves in SCOOP totaled 492 MMBoe as of December 31, 2017 , an increase of 4% compared to December 31, 2016 due to reserves added from our drilling program, continued improvement in recoveries driven by advances in optimized completion designs, and upward reserve revisions prompted by higher commodity prices in 2017. Our inventory of proved undeveloped drilling locations in SCOOP totaled 336 gross (230 net) wells as of December 31, 2017 .

In 2018 , we plan to invest approximately $465 million to drill, complete and initiate production on 160 gross ( 44 net) operated and non-operated wells in the SCOOP play. We plan to average approximately seven operated rigs and one completion crew in SCOOP throughout 2018 , an increase from five rigs as of December 31, 2017 . Our 2018 drilling program will continue to focus on expanding the known productive extent of the SCOOP Woodford, Springer and Sycamore formations, while focusing on areas that provide opportunities for converting undeveloped acreage to acreage held by production, increasing capital efficiency, reducing finding and development costs, and improving rates of return.

STACK

STACK is a significant resource play located in the Anadarko Basin of Oklahoma characterized by stacked geologic formations with major targets in the Meramec, Osage and Woodford formations. As of December 31, 2017 , we controlled one of the largest leasehold positions in STACK with approximately 389,400 gross ( 212,400 net) acres under lease. A significant portion of our STACK acreage is located in over-pressured portions of Blaine, Dewey and Custer counties of Oklahoma where we believe the reservoirs are typically thicker and deliver superior production rates relative to normal-pressured areas of the STACK petroleum system.