ENERCOM - Annual Report Portfolio 2017

ANNUAL REPORTS

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PORTFOLIO 2017

WHITING PETROLEUM Annual Report 2016

RESURGENT 2 016 A N N U A L R E P O R T

Re·sur·gent – adjective – rising again, as to new life, vigor Our team’s dedication and work in 2016 have positioned Whiting with a balance sheet and enhanced asset base to support strong future growth for years to come.

About the Cover

Whiting has a sharp focus on driving repeatable and profitable oil growth from our core resource plays in the Williston Basin of North Dakota and Montana and the DJ Basin of Colorado. In the Williston Basin, we target the Bakken and Three Forks formations. At our Redtail play in the DJ Basin, we target the Niobrara “A”, “B” and “C” and Codell/Fort Hays formations.

No detail is too small. Using state-of-the-art technology, our teams analyze the reservoir at a molecular level, enabling us to optimize well completions and high-grade assets.

Our dedication to better understanding our reservoirs and generating efficiencies has reduced well costs in the Williston and Eastern DJ Basins while raising per-well estimated ultimate recoveries (EURs). This improves our returns on drilling and enhances our ability to deliver long-term value to shareholders through the commodity price cycle.

ForwardLooking Statements

This annual report contains forward-looking statements. Please refer to “Forward-Looking Statements” on page 63 of the attached Annual Report on Form 10-K for an explanation of these types of statements. These statements should be considered in light of the “Risk Factors” set forth on page 18 of the attached Annual Report on Form 10-K.

01 Corporate Overview 02 Financial and Operations Summary 04 Letter to the Shareholders 06 Asset Overview Table of Contents

09 Operational Focus 11 Productivity Focus 13 Environmental Focus 14 Board of Directors 15 Form 10-K

Abbreviations

Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil, NGLs and other liquid hydrocarbons.

MBOE: One thousand BOE.

Bcf: One billion cubic feet, used in reference to natural gas.

Mcf: One thousand cubic feet, used in reference to natural gas.

BOE: One stock tank barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals six Mcf of natural gas and one Bbl of crude oil equals one Bbl of natural gas liquids.

MMBbl: One million barrels.

BOE/D: BOE per day.

NGLs: Natural gas liquids.

BTU: British Thermal Unit.

Completion: The process of preparing an oil and gas wellbore for production through the installation of permanent production equipment, as well as perforation and fracture stimulation to optimize production.

MBOE/D: MBOE per day.

MMBOE: One million BOE. MMLb: One million pounds.

Corporate Overview

Headquartered in Denver, Colorado, Whiting Petroleum Corporation is an independent oil and gas company that develops, produces, acquires and explores for crude oil, natural gas and natural gas liquids in the Rocky Mountains region of the United States. We are currently focused on organic drilling and development activity, both on grassroots oil plays and on the development of previously acquired properties. Whiting targets projects that provide the opportunity for repeatable success and meaningful production growth. We lead the industry with our competitive assets, dedication to technology and record setting results. Whiting is a competitive company with a strong plan for the future. The Company’s shares are traded on the New York Stock Exchange under the stock symbol WLL.

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FINANCIAL & OPERATIONS SUMMARY (IN MILLIONS, EXCEPT PER SHARE AMOUNTS, PER UNIT PRICES, RATIOS AND WELL AND ACREAGE STATISTICS)

2016

INCOME STATEMENT & CASH FLOW

2015

2014

2013

2012

2,092.5

Oil, NGL & Natural Gas Sales

$ 1,285.0

$

$ 3,024.6

$ 2,666.5

$ 2,137.7

Net Income (Loss)

$ (1,339.1)

$ (2,219.3)

$ 64.7

$ 366.0

$ 414.1

Earnings (Loss) per Common Share, Diluted

$ (5.32)

$ (11.35)

$

0.53

$ 3.06

$ 3.48

Weighted Average Shares Outstanding, Diluted

251.869

195.472

122.519

119.588

119.028

Net Cash Provided by Operating Activities

$ 1,051.4

$ 1,815.3

$ 1,744.7

$ 1,401.2

Net Cash Used in Investing Activities

(222.6) $

$ (1,982.1)

$ (2,860.5)

$ (1,902.5)

$ (1,780.3)

Net Cash Provided by (Used in) Financing Activities

(315.3) $

$ 868.7

$ 423.9

$ 812.4

$ 408.1

2016

2015

2014

2013

2012

$ 595.0

BALANCE SHEET Total Assets

$

9,876.1

$ 11,389.1

$ 13,993.1

$ 8,802.5

$ 7,265.7

Long-Term Debt

$ 3,535.3

$ 5,197.7

$ 5,602.4

$ 2,622.9

$ 1,793.2

Total Equity

$ 5,149.2

$ 4,758.6

$

$ 3,836.7

$ 3,453.2

Debt-to-Capitalization Ratio PRODUCTION & AVERAGE COMMODITY PRICES Oil Production, MMBbl NGL Production, MMBbl

5,703.0

41

52

2016

2015

2014

2013

2012

34.0

47.2

33.5

27.0

23.1

%

50

%

41

%

%

34%

6.6

5.5

3.3

2.8

2.8

Natural Gas Production, Bcf

41.4

41.1

30.2

26.9

25.8

Total Production, MMBOE

47.5

59.6

41.8

34.3

30.2

Oil Price, per Bbl, Excluding Hedging

$

34.36

$ 40.95

$ 81.50

$ 90.39

$ 83.86

Natural Gas Liquids Price, per Bbl

$

8.88

$ 12.67

$ 39.17

$ 40.41

$ 39.36

Natural Gas Price, per Mcf

$

1.40

$ 2.20

$ 5.53

$ 4.04

$ 3.42

Sales Price, per BOE, Net of Hedging

$

30.22

$ 38.76

$ 73.38

$ 76.76

$ 69.85

YEAR-END 2016 WELL COUNT & ACREAGE STATISTICS

GROSS

NET

Total Productive Wells

4,687

1,917

Developed Acreage

849,306

517,169

Undeveloped Acreage

362,400

247,663

RESERVES & PRODUCTION PER REGION

26.1

%

CENTRAL ROCKY MOUNTAINS

0.7%

77 .

OTHER

CENTRAL ROCKY MOUNTAINS

73.2%

NORTHERN ROCKY MOUNTAINS

615.5 MMBOE PROVED RESERVES AS OF 12/31/2016

2

%

0 7% .

OTHER

91.6%

NORTHERN ROCKY MOUNTAINS

Q4 2016–118.9 MBOE/D PRODUCTION

2016 Highlights

108,850BOE/D

Q4 2016 Williston Basin net production 3% INCREASE OVER Q3 2016

900

MBOE

Williston Basin 5+ million pound completions TYPE CURVE

1,500

MBOE

Williston Basin 10+ million pound completions TYPE CURVE

$2.4BILLION

Debt reduction THROUGH FEB. 2017

$1.9BILLION

Strong liquidity position AS OF 12/31/2016

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RESURGENT Dear Fellow Shareholders, In 2016, initiatives Whiting embarked on in 2015 to strengthen its balance sheet came to fruition. Since the beginning of 2015, we generated $2.8 billion in proceeds from asset sales and innovative capital market transactions. This exceeds the $2.5 billion of debt we assumed in the Kodiak transaction, which closed in December of 2014. Throughout this process, we maintained our focus on operational execution and the application of innovative well completion technology to improve capital efficiency. This positions Whiting for strong growth.

At our core Bakken/Three Forks play in the Williston Basin, Whiting pioneered the application of new well technology to dramatically improve productivity. As measured by 90-day average production per well, productivity increased 42% in 2016 year-over-year and has increased 84% since 2014. We achieved this through new well designs that enable us to stimulate more rock using additional entry points and larger sand volumes. The average sand volume per well increased from 3.6 million pounds in 2014 to over 8 million pounds in Q4 2016. Applying the same metric of 90-day average production per well to all significant operators in the Williston Basin (10 or more wells drilled in a 12-month period), Whiting emerges as the Bakken champion with the most productive wells. We plan to apply similar technology in our Redtail Niobrara/Codell play in the DJ Basin of Colorado with the potential for significant increases in productivity.

In addition to more productive wells, we have also increased operational efficiencies. In the Williston Basin, we lowered our spud to rig release times by 36% since the beginning of 2014. In the DJ Basin, we lowered our spud to rig release times by 50% over the same period.

Our focus on safety and the environment remains strong. Our gas capture rate in both plays was typically 90% or greater in 2016. We also led the way in North Dakota working with state regulators to implement a new, more rigorous inspection regime for methane emissions. On the safety side, we had one of our best years ever as incidents decreased significantly in 2016. We are committed to the health and welfare of our employees as they perform the vital task of providing reliable and affordable energy for our country.

As we look ahead, we believe the potential of our top tier assets and talented employees will be realized through sustainable growth and shareholder value creation. Our 2017 outlook calls for 23% production growth from the first quarter to the fourth quarter.

We worked to secure this outlook by building a strong hedge profile with 49% of our forecasted 2017 production hedged at attractive prices. This contributes to our goal of strong growth in net asset value while maintaining a solid balance sheet. Thank you for your support as shareholders as Whiting emerges stronger than ever from one of the most challenging downturns in the history of oil markets.

Sincerely,

JAMES J. VOLKER CHAIRMAN OF THE BOARD, PRESIDENT AND CHIEF EXECUTIVE OFFICER FEBRUARY 23, 2017

ABOVE: James J. Volker participates as a Keynote Panel Speaker at the Williston Basin Petroleum Conference.

4

A Focused Company

Headquarters Williston Basin Redtail

RIGHT: Drilling rig on the Razor 25M-2402 well with the Pawnee Buttes in the background.

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ASSET OVERVIEW Williston Basin

Q4 2016 Production of 108,850 BOE/D Whiting is one of the largest producers in the oilrich Williston Basin of North Dakota and Montana, which encompasses the prolific Bakken and Three Forks formations. Since our Sanish Field discovery in 2007, we’ve been a leader in the development of new well designs, completion technologies and operating processes. We control one of the largest acreage positions in the Williston Basin with 443,839 net acres that hold approximately 5,300 potential gross drilling locations.

WILLIAMS MOUNTRAIL

MCKENZIE

MCLEAN

DUNN

Large Acreage Position in the Core of the Play WLL Acreage

DJ Basin

Q4 2016 Production of 9,210 BOE/D In the oil-prone sweet spot of the eastern DJ Basin of Colorado, we have 132,184 net acres.

Similar to our Bakken and Three Forks acreage position, we are utilizing the latest technology to develop multiple horizons, which include the Niobrara “A”, “B” and “C” and Codell/Fort Hays formations. This provides us with an estimated 5,400 potential gross drilling locations.

WYOMING Laramie Kimball

REDTAIL FIELD AREA Weld Larimer

Morgan

WATTENBERG FIELD AREA

ER

IN

DO

M

AL

LT

BE

RA

LO

Boulder

N

O FC

O

N

TE

EX

SIO

Economic sweet spot in the oil window WLL Acreage

6

Area of Resistivity

118,890

BOE/D

Net Production in Q4 2016

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OPERATIONAL FOCUS Improves Performance

8

Operational Focus

OPERATIONAL FOCUS Whiting is a leader in both drilling and completion technology. It has adopted the latest drill bit technology and pioneered new completion techniques to maximize efficiency.

50

Faster Drilling Times and Longer Laterals In Whiting’s Redtail Niobrara/Codell play in the DJ Basin, the average time to drill a well from spud to rig release has decreased 50% to 5.8 days in Q4 2016 since the beginning of 2014. This was driven by more efficient operations and a new monobore wellbore design that eliminates intermediate casing. We continue to increase the number of longer lateral 1,280-acre spaced wells in our drilling program. In 2016, we drilled 34 1,280-acre spaced wells in an average time of 4.4 days from spud to total depth and 7.4 days from spud to spud. Our 1,280-acre spaced wells have the potential to deliver approximately 40% higher reserves for only a 12.5% increase in cost relative to our standard 960-acre spaced wells.

Redtail Drilling Time

%

Improvement

from Beginning of 2014

6.4

5.9

6.2

6

5.8

8

9.5

12.4

12.4

11.2

10.7

9.2

Average Days

10

11.9

12

11.5

14

4 2 0

Q1

Improving Performance

Q2

Q3

Q4

Q1

Q2

2014

Whiting continues to improve Bakken well productivity by increasing sand concentration to enlarge stimulated rock volume. In the Bakken, our 90-day average rate during 2016 was 42% higher than 2015 and 84% higher than 2014. The new completion technique and resulting productivity gains increased Whiting’s Bakken targeted type curve by 50% to 900 MBOE from 600 MBOE in 2014. The Redtail Field in the DJ Basin is also delivering attractive results. In 2016, we shifted our mix towards longer 10,000’ laterals and built a robust inventory of 105 DUCs (drilled uncompleted wells). This should contribute to highly capital efficient growth in 2017 at Redtail.

Q3

Q4

Q1

Q2

2015

36%

Q3

Q4

2016

Improvement

13.1

13.9

12.2

13.1

10

14.6

Q1

15.5

Q4

15.9

18.2

from Beginning of 2014

17.7

18.4

15

19.6

Average Days

20

21.6

Williston Basin Drilling Time

Q3

Q4

5 0

Q1

Q2

Q3

Q2

2014

Q3

Q4

Q1

Q2

2015

2016

Enhanced Completions Increase Well Productivity in the Williston Basin

1,600

576

400

%

84

834 665

600

%

88

985

800

839

BOEPD

1,000

1,057

64

746

%

1,200

1,253

1,375

1,400

200 0

ABOVE: Worker on a drilling rig stacks pipe while drilling a Redtail well.

30-Day Avg. BOEPD

60-Day Avg. BOEPD 2014

2015

90-Day Avg. BOEPD 2016

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9

PRODUCTIVITY FOCUS Powers Industry Leading Results

10

Productivity Focus

PRODUCTIVITY FOCUS Technology increases recovery efficiency and reserves per well. It has empowered our operations team to achieve industry leading productivity while reducing costs.

Enhanced Completion Wells Continue to Track 900 MBOE Type Curve after 265 Days

997

1,000

22

10

Wells

33

14

34

160,000

700

140,000

27

Super Completion 10+MMLb Fracs Continue to Deliver Outstanding Results 250,000

OE

90

PEER G 328

18

PEER F

PEER C

17

0

PEER E

PEER B

200

PEER D

400

567

572

680

692

600

B 0M

180,000

120,000 100,000

00

1,5

200,000

E

MBO

BOE

BOE

816

800

Enhanced Completion 5+MMLb Fracs Tracking 900 MBOE EUR Type Curve 200,000

1,203

1,200

PEER A

During the second half of 2016, Whiting brought on production its initial three super completions. Two of the wells, the Carscallen 3114-4H completed with 13.6 million pounds of sand, and the P Bibler 155-99-16-31-30-1H completed with 10.1 million pounds of sand, were located approximately ten miles apart in Williams County, North Dakota. The third well, the Rolla Federal 11-3-1TFHU, was completed with 10.0 million pounds of sand and completed in McKenzie County, North Dakota. On average, the wells are tracking above a 1,500 MBOE type curve after 120 days on production.

for Wells Completed between December 2015 and Novemeber 2016

WLL

Super Completion Wells Tracking 1,500 MBOE Type Curve after 120 Days

90 -Day Average

BOEPD

Whiting’s initial set of 48 enhanced completion wells in the Williston Basin continues to produce in line with a 900 MBOE type curve after 265 days. These wells span Whiting’s acreage and are located in Billings, Dunn, McKenzie, Mountrail, Stark and Williams counties of North Dakota. On average, these wells were completed with 36 stages and 6.6 million pounds of sand.

Williston Basin

900

150,000

OE

MB

E

MBO

100,000

80,000

3-Well Avg.

Enhanced Completion Average

60,000

900 MBOE

40,000

1,500 MBOE

50,000

700 MBOE

900 MBOE

20,000 0.0 30

60

90

120

150

180

210

240

270

20

40

Days

60

80

100

120

140

160

180

200

Days

Williston Basin Well Costs Down 14% Since 2014 8.4

AFE Cost per year

8.2 8.0 7.8

14%

$MM

7.6

Dec

rea

7.4

se

7.2

6.4

ABOVE: Whiting pad and reclamation site in Williams County, North Dakota.

$7.1

6.6

$7.9

6.8

$8.3

7.0

2014

2015

2016

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ENVIRONMENTAL FOCUS Protects Nature and Engages Community

12

Environmental Focus

ENVIRONMENTAL FOCUS Whiting is deeply committed to protecting the environment as we safely and responsibly develop our resources.

We Are Good Stewards of the Environment Whiting uses FLIR (forward looking infrared) sensing technology to inspect facilities and reduce methane emissions. We have a team of highly trained technicians that frequently inspect well sites and tank batteries to gather valuable data and promptly initiate corrective action if needed.

Whiting also works diligently to reduce its impact on the environment. In 2016, our extensive pipeline network at our Redtail field in Weld County, Colorado saved over 60,000 truck trips related to transportation of produced fluids (oil, water and NGLs).

Our natural gas processing plant captures over 90% of methane emitted from our wells and has provided approximately 990 mcf of fuel gas to the field to power frac fleets, drilling rigs and production equipment. On a BTU basis, this replaced 8.7 million gallons (207,000 Bbl) of diesel.

Working with Our Communities During the well planning process, Whiting is committed to working with landowners and county, state and federal officials to minimize its impact on the environment and community. We consult with county planning officials and Colorado Oil and Gas Conservation Commission (COGCC) personnel regarding optimal site location and layout. We work with COGCC personnel on reclamation of pads after initial production to reduce and minimize environmental impacts for the remainder of the pad’s life.

We identify best practices for seed mixture, ground preparation, soil stockpiling and handling, cuttings remediation and storm water management to preserve the natural environment.

Safety is a Part of Our Daily Life Whiting’s safety programs and associated values are ingrained in our culture. We have adopted a robust training program that is a priority for all of our company employees and has resulted in a significant decrease in safety incidents. Our focus is reflected in our continued industry leading TRIR and DART statistics.

Rolling 12 -Month Average Rate/Month 2.00 1.80 1.60 1.40

Rate

1.20 1.00 0.80 0.60 0.40 0.20 0.00

2014 TRIR - Total Recordable Incident Rate TRIR Rolling Average Linear (TRIR Rolling Average)

2015

2016

DART - Days Away, Restricted and/or Transfered

ABOVE: Reclamation and production site in Williams County, North Dakota.

DART Rolling Average Linear (DART Rolling Average) 2016 AN N U AL RE PO RT | W H IT IN G P E T R OL E UM COR P OR AT I ON

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BOARD OF DIRECTORS

JAMES J. VOLKER

THOMAS L. ALLER

D. SHERWIN ARTUS

JAMES E. CATLIN

PHILIP E. DOTY

WILLIAM N. HAHNE

CARIN S. KNICKEL

MICHAEL B. WALEN

70, Chairman of the Board, President and Chief Executive Officer, has been a director of Whiting Petroleum Corporation since 2003 and a director of Whiting Oil and Gas Corporation since 2002. He joined Whiting Oil and Gas Corporation in 1983 as Vice President of Corporate Development and served in that position through 1993. In 1993, he became a contract consultant to Whiting Oil and Gas Corporation and served in that capacity until 2000, at which time he became Executive Vice President and Chief Operating Officer. Mr. Volker was appointed President and Chief Executive Officer of Whiting Oil and Gas Corporation in 2002. Mr. Volker was co-founder, Vice President and later President of Energy Management Corporation from 1971 through 1982. He has 45 years of experience in the oil and natural gas industry. Mr. Volker has a degree in finance from the University of Denver, a MBA from the University of Colorado and has completed H. K. VanPoolen and Associates’ course of study in reservoir engineering.

73, is Chairman of the Audit Committee and has been a director of Whiting Petroleum Corporation since 2010. Mr. Doty is a certified public accountant. Since 2007, Mr. Doty has been counsel to EKS&H LLP, the largest Colorado-based accounting and consulting firm, where he previously was a partner from 2002 to 2007. From 1967 to 2000, he worked at Arthur Andersen and Co., where he was a partner since 1978 and served as the audit partner and head of the Denver office oil and gas practice until his retirement in 2000. He is a graduate of Drake University with a Bachelor’s degree in accounting.

1 4

68, is Chairman of the Compensation Committee and has been a director of Whiting Petroleum Corporation since 2003. Mr. Aller retired as Senior Vice President of Operations Support for Alliant Energy Corporation in 2014.

He served as Senior Vice President-Energy Resource Development of Alliant Energy Corporation from January 2009 to 2013 and President of Interstate Power and Light Company since 2004. Prior to that, he served as President of Alliant Energy Investments, Inc. since 1998 and interim Executive Vice President—Energy Delivery of Alliant Energy Corporation since 2003 and Senior Vice President—Energy Delivery of Alliant Energy Corporation since 2004. From 1993 to 1998, he served as Vice President of IES Investments.

He received his Bachelor’s Degree in Political Science from Creighton University and his Master’s Degree in Municipal Administration from the University of Iowa.

65, is Lead Director, Chairman of the Nominating and Governance Committee and has been a director of Whiting Petroleum Corporation since 2007. Mr. Hahne was Chief Operating Officer of Petrohawk Energy Corporation from July 2006 until October 2007. Mr. Hahne served at KCS Energy, Inc. as President, Chief Operating Officer and Director from April 2003 to July 2006, as Executive Vice President and Chief Operating Officer from March 2002 to April 2003 and in other management positions prior to that. He is a graduate of Oklahoma University with a BS in Petroleum Engineering and has over 40 years of extensive technical and management experience with independent oil and gas companies including Unocal, Union Texas Petroleum Corporation, NERCO, The Louisiana Land and Exploration Company (LL&E) and Burlington Resources, Inc.

80, has been a director of Whiting Petroleum Corporation since 2006. Mr. Artus joined Whiting Oil and Gas Corporation in January 1989 as Vice President of Operations and became Executive Vice President and Chief Operating Officer in July 1999. In January 2000, he was appointed President and Chief Executive Officer. Mr. Artus became Senior Vice President in January 2002 and retired from the Company on April 1, 2006.

Prior to joining Whiting, he was employed by Shell Oil Company in various engineering research and management positions. From 1974-1977, he was employed by Wainoco Oil and Gas Company as Production Manager. He was a co-founder and later became President of Solar Petroleum Corporation, an independent oil and gas producing company. He has over 54 years of experience in the oil and natural gas business. Mr. Artus holds a Bachelor’s Degree in Geological Engineering and a Master’s Degree in Mining Engineering from the South Dakota School of Mines and Technology. He is a registered Professional Engineer in Colorado, Wyoming, Montana and North Dakota. Mr. Artus is a member, and a past officer, of the Society of Professional Well Log Analysts and is a member of the Society of Petroleum Engineers.

60, has been a director of Whiting Petroleum Corporation since 2015. Ms. Knickel’s energy industry experience includes over three decades in operations leadership in refining, marketing, transportation, exploration and production for ConocoPhillips. She also held roles in business development, strategic planning and commodity trading, and led the company’s specialty products business from 2001 to 2003. She became Vice President of Global Human Resources in 2003 and served on the company’s management committee from that time until she retired in May 2012.

Ms. Knickel also served as Assistant Dean for Programs and Talent for the University of Colorado College of Engineering from January 2013 through July 2014 and currently serves on the school’s Engineering Advisory Council.

She has a Bachelor’s Degree in Marketing from the University of Colorado and a Master’s Degree in Management Science from the Massachusetts Institute of Technology.

70, has been a director of Whiting Petroleum Corporation since 2014. Mr. Catlin was a cofounder of Kodiak Oil & Gas (USA), Inc. Mr. Catlin served as a director of Kodiak since February 2001, Chairman of the Board from July 2002 until June 2011, Secretary from July 2002 to May 2008, Chief Operating Officer from June 2006 until June 2011 and Executive Vice President of Business Development since June 2011. Mr. Catlin has over 40 years of geologic experience primarily in the Rocky Mountain Region. Mr. Catlin was an owner of CP Resources LLC, an independent oil and natural gas company from 1986 to 2001. Mr. Catlin was a Founder, Vice President and Director of Deca Energy from 1980 to 1986 and worked as a district geologist for Petroleum Inc. and Fuelco prior to this time. He received a Bachelor of Arts and a Master’s of Science Degree in Geology from the University of Northern Illinois in 1973.

Mr. Catlin has extensive training and experience with respect to geology and executive level experience working with oil and natural gas companies.

68, has been a director of Whiting Petroleum Corporation since 2013. Mr. Walen was the Senior Vice President—Chief Operating Officer of Cabot Oil and Gas Corporation from January 2001 until May 2010 and served in other management and exploration positions prior to that time. He has over 40 years of exploration and management experience with independent oil and gas companies including PetroCorp Inc., Patrick Petroleum Co., TXO Production Co. and Tenneco Oil Company. Mr. Walen holds a Bachelor’s Degree in Geology from Central Washington University and a Master’s Degree in Geology from Western Washington University.

EXECUTIVE OFFICERS

OTHER OFFICERS

BOARD OF DIRECTORS

James J. Volker Chairman of the Board, President and Chief Executive Officer

Bill L. Cadman Vice President, Corporate and Government Relations

James J. Volker (Since 2003) Chairman of the Board, President and Chief Executive Officer

Michael J. Stevens Senior Vice President and Chief Financial Officer

Michael R. Craig Vice President, Information Technology

William N. Hahne +^ (Since 2007) Lead Director Past Chief Operating Officer Petrohawk Energy Corporation

Peter W. Hagist Senior Vice President, Planning

Eric K. Hagen Vice President, Investor Relations

Rick A. Ross Senior Vice President, Operations

Mark D. Sonnenfeld Vice President, Geoscience for Whiting Oil and Gas Corporation

Thomas L. Aller*+ (Since 2003) Retired President Interstate Power and Light Company an Alliant Energy Company

Mark R. Williams Senior Vice President, Exploration and Development

Bruce L. Taton Vice President, Marketing for Whiting Oil and Gas Corporation

D. Sherwin Artus ^ (Since 2006) Retired President and CEO Whiting Petroleum Corporation

Bruce R. DeBoer Vice President, General Counsel and Corporate Secretary

Douglas L. Walton Vice President and National Drilling Manager for Whiting Oil and Gas Corporation

James E. Catlin (Since 2014) Past Executive Vice President and Director Kodiak Oil and Gas Corporation

Heather M. Duncan Vice President, Human Resources

Philip E. Doty* ^ (Since 2010) Certified Public Accountant

Brent P. Jensen Chief Accounting Officer Vice President, Finance and Treasurer

Carin S. Knickel +^ (Since 2015) Past Vice President ConocoPhillips

Steven A. Kranker Vice President, Reservoir Engineering and Acquisitions

Michael B. Walen *+ (Since 2013) Past Chief Operating Officer Cabot Oil and Gas Corporation

David M. Seery Vice President, Land

* Audit Committee

+ Compensation Committee

^ Nominating and Governance Committee

CORPORATE OFFICES

TRANSFER AGENT

INFORMATION UPDATES

Whiting Petroleum Corporation 1700 Broadway, Suite 2300 Denver, Colorado 80290-2300 Tel: 303.837.1661 Fax: 303.861.4023 www.whiting.com

Please direct communication regarding individual stock records and address changes to:

Whiting’s quarterly financial results and other information are available on our website at www.whiting.com

Computershare Trust Company, N.A. 8742 Lucent Blvd., Suite 225 Highlands Ranch, Colorado 80129 Tel: 303.262.0600 Fax: 303.262.0700 www.computershare.com

ANNUAL REPORT ON FORM 10-K

INVESTOR RELATIONS Securities analysts, investors and the financial media should contact: Eric K. Hagen Vice President, Investor Relations Tel: 303.837.1661

STOCK EXCHANGE LISTING New York Stock Exchange, trading symbol: WLL

INDEPENDENT PETROLEUM ENGINEERS Cawley, Gillespie & Associates, Inc.

INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Deloitte & Touche LLP

Upon request, the Company will provide, without charge, copies of the 2016 Annual Report on Form 10-K as filed with the Securities and Exchange Commission

ANNUAL MEETING Tuesday, May 2, 2017 10:00 A.M. (Mountain Daylight Time) The Grand Hyatt Hotel Capitol Peak Ballroom 555 17th Street, 38th floor Denver, Colorado 80202

1700 Broadway, Suite 2300 Denver, Colorado 80290-2300 Tel: 303.837.1661 Fax: 303.861.4023 www.whiting.com

NYSE: WLL

UNIT CORPORATION Annual Report 2016

A DIVERSIFIED ENERGY COMPANY

ANNUAL REPORT 2016

CORPORATE PROFILE Unit Corporation is a diversified energy company engaged through its subsidiaries in the exploration for and production of oil, natural gas, and natural gas liquids, the contract drilling of onshore oil and natural gas wells, and the gathering and processing of natural gas. Operations are mainly located in the Mid-Continent, Rocky Mountain, and Gulf Coast regions with additional activity in the Permian and Appalachian Basins.

CASPER OFFICE PITTSBURGH OFFICE

DENVER OFFICE

Mississippian Basin TULSA HEADQUARTERS

Anadarko Basin

Arkoma Basin

OKLAHOMA CITY OFFICE

Permian Basin Gulf Coast Basin HOUSTON OFFICE

CONTRACT DRILLING OIL & NATURAL GAS MIDSTREAM

FINANCIAL INFORMATION Year Ended December 31, ($ in thousands)

2016

2015

Total Revenues

$602,177

$854,231

$1,572,944

$1,351,850

$1,315,123

Capital Expenditures 1

$186,713

$561,632

$987,097

$703,984

$1,360,866

$2,479,303

$2,799,842

$4,463,473

$4,010,546

$3,747,688

$800,917

$918,995

$801,908

$633,852

$702,927

Shareholders’ Equity

$1,194,070

$1,313,580

$2,332,394

$2,173,392

$1,974,301

Total Capitalization

$1,994,987

$2,232,575

$3,134,302

$2,807,244

$2,677,228

Total Assets Long-Term Debt

1

Capital expenditures (cash basis) including acquisions.

2014

2013

2012

TO OUR SHAREHOLDERS

A

s we had anticipated at its outset, 2016 was another year of challenges ushered in by the continuation of low commodity prices. While there is no substitute for experience in dealing with such situations, experience does not make the process any more pleasant. We have dealt with the many issues that have confronted both our industry and our company during the year, and we have taken the actions we have deemed appropriate given the circumstances.

As a result, we believe we have emerged much stronger and better positioned as we move into 2017.

One of our focuses for 2016 was balance sheet preservation. We addressed this task by significantly reducing capital expenditures and working diligently to manage costs in every facet of our business.

By maintaining our spending within the cash flow provided by our operations throughout the year, we were able to reduce long-term debt by nearly $120 million. This has significantly enhanced our liquidity position and improved our debt profile. These actions did not occur without some consequence. Our reduced capital spending, lower average commodity prices, and the sale of some non-core assets resulted in a year-over-year reduction of oil and natural gas reserves.

As anticipated, 2016 average daily oil and natural gas production also declined as compared to 2015. We have initiated steps to begin reversing these effects.

We recently announced our capital expenditures plan for 2017. As is our practice, and as our shareholders have grown to expect, we are establishing our initial budget in line with anticipated cash flow plus any proceeds from the continuation of our non-core asset divestiture plan. It is our sense that we have reduced our indebtedness to a level sufficient to maintain a strong financial profile, so that cash flows generated from our various operating activities can now be fully devoted to growth rather than continued debt reduction.

During the fourth quarter, our oil and natural gas segment reinitiated its drilling activity. We were very excited to restart our drilling activities and look forward to returning this segment to a growth mode. At this time, our plan is to operate two to three drilling rigs throughout the year. With this cadence, we anticipate that production will trough during the first quarter and begin to sequentially grow thereafter. We expect 2017 production will average between 43 MBoe and 45 MBoe per day. We have a multiple year drilling inventory of prospective wells that we believe compete very favorably economically even with the most popular basins across the country. Further, this inventory will help facilitate the resumption of reserve growth. Our capital expenditure budget for the oil and natural gas segment is $188 million, an increase of 57% over 2016.

Our contract drilling segment has rebounded well from a low of 13 operating drilling rigs in the second quarter reaching 21 operating rigs at year end, and presently we have 26 operating rigs, a 100% increase from the trough. This growth is continuing. We have received

contracts to return four additional drilling rigs to service during the latter part of the quarter. Another bright spot for the segment is the continued customer preference of our BOSS drilling rig which is performing exceptionally well. Despite the number of AC rigs of other contractors that are presently stacked, one of our customers contracted for our ninth BOSS drilling rig, which was built and placed into service at the end of the fourth quarter. Our SCR rigs continue to have strong demand as noted by 17 of our SCR rigs currently in operation with an additional four contracted to return to work as previously mentioned. Our capital expenditures budget for the drilling segment is $24 million, a 25% increase from 2016.

Our midstream segment has performed very well during the year.

Per day gathered volumes increased 18% year over year. Due to our prior focus on converting contracts to fee based pricing as opposed to commodity based pricing, the segment’s cash flow has held up very well. In fact, the segment generated its second highest level of cash flow before intercompany eliminations in its history during the year. We operated primarily in an ethane rejection mode at our gas processing facilities throughout the year due to uneconomic NGL pricing. We are optimistic on the improvement of NGL pricing over the next few years, and this segment is positioned very well to take full advantage of the price improvement with nominal additional capital investment. The capital expenditures budget for the midstream segment is currently anticipated to be $13 million.

On another note, Chairman John Nikkel retired from our Board of Directors on December 31, 2016. J. Michael Adcock, a current board member, was elected our new chairman. John was an incredible asset to Unit for the 33 years he was with the company, helping to lead our efforts to grow our diversified operations. His experience and knowledge in this industry were unparalleled. While we will greatly miss John, Mike Adcock has now taken the helm of our board. Mike’s broad experience and knowledge of both the industry and Unit, will help guide our company as we move forward. We look forward to his leadership.

Finally, we are optimistic as there are many positive trends emerging that have certainly brightened our outlook. Commodity prices appear to be headed in a more favorable direction. The increase in industry activity level appears to affirm this view. We believe we are continuing to take the appropriate steps to navigate this business cycle. We have emerged a much leaner organization, and we believe positioned very well to take full advantage of the improvements to create additional value for our shareholders.

Larry D. Pinkston Chief Executive Officer and President February 23, 2017

1

OIL & NATURAL GAS SEGMENT

D

uring the year, we produced 17.3 MMBoe, a decrease of 14% from the 20.0 MMBoe produced during 2015. Liquids (oil and NGLs) production represented 46% of our total equivalent production for the year.

The suspension of drilling activities at the end of the first quarter 2016, lower commodity prices, and divestitures during the year resulted in the reduction of 2016’s total proved reserves as compared to 2015. At the end of 2016, our total proved reserves were 117.8 MMBoe, or 706.6 Bcfe, 13% less than 2015. Overall, 84% of our estimated proved reserves are proved developed. Estimated proved reserves were 13% oil, 29% natural gas liquids (NGLs), and 58% natural gas.

Our 2016 oil and natural gas revenues decreased 24% to $294.2 million. The price we received for our natural gas averaged $2.07 per Mcf, a decrease of 21% from 2015.

Our average oil price decreased 20% from 2015 to $40.50. Our NGLs price averaged $11.26 per barrel, up 11% over 2015.

In our Wilcox play, in southeast Texas, in Polk, Tyler, and Hardin Counties, we continued our Wilcox recompletion and workover program. There were 10 new behind pipe recompletions during the fourth quarter, which increased combined production on these wells by 9.8 MMcf per day and 300 barrels of oil per day at a total capital cost of $3.0 million. Annual production from our Wilcox play averaged 94.1 MMcfe per day (12% oil, 31% NGLs, 57% natural gas) which is an increase of approximately 22% compared to 2015. We anticipate completing approximately four vertical wells and three horizontal wells during 2017. In addition, we plan to complete approximately 10 - 15 behind pipe recompletions during the year.

In our SOHOT area, located primarily in Grady County, Oklahoma, drilling activities were curtailed during the first quarter of 2016. Annual production from the SOHOT area averaged 65.1 MMcfe per day (27% oil, 22% NGLs, 51% natural gas), a decrease of approximately 15% compared to 2015, which was in line with expections. We resumed drilling in the area during the fourth quarter. Two horizontal wells were drilled recently and completed. Production is being monitored for a few months with plans to begin drilling additional wells in the second quarter. We anticipate completing approximately seven horizontal Marchand wells in our SOHOT play during 2017.

In our Texas Panhandle Granite Wash play, we resumed drilling in December with an extended length lateral in the A2 interval of Buffalo Wallow that is anticipated to be completed in late February. The Dixon 5554 XL #1H, which was completed in the C1 interval, continues to perform at a rate over 50% better than its type curve forecast.

Annual production from the Texas Panhandle averaged 93.7 MMcfe per day (11% oil, 37% NGLs, 52% natural gas), which is a decrease of approximately 23% compared to 2015. We plan to continuously operate at least one drilling rig in the Granite Wash during 2017, which we anticipate to result in nine new extended length lateral wells.

2

RETURN TO GROWTH IN

2017

CONTRACT DRILLING SEGMENT

D

uring the fourth quarter of 2016, we completed the construction of our ninth BOSS drilling rig, which was contracted and placed into service. The BOSS drilling rig is a proprietary rig design that we began building in 2013. It is a 1,500 horsepower AC drilling rig that combines the best technological innovations from high-tech drilling rig designs into a single unique drilling rig that meets today’s demands. One of its design features allows for a quick assembly substructure which can be moved in fewer loads reducing the number of permits needed to move the drilling rig to a new location. The BOSS drilling rig provides us with the leading design features needed to meet the increasing technical demands of our customers.

ALL 9 BOSS DRILLING RIGS ARE IN OPERATION

The decline in commodity prices during 2015 and 2016 resulted in a decline in the demand for the use of our drilling rigs. During 2016, utilization continued downward, bottoming out in May at 13 operating drilling rigs. As commodity prices began to improve during the remainder of the year, we exited 2016 with 21 active rigs. We currently have 26 drilling rigs operating under contract. We also have contracts in place to return four additional drilling rigs to service during the first quarter of 2017.

Currently, we have ten long term contracts with original terms ranging from six months to three years. Eight of these contracts are up for renewal in 2017 and two are up for renewal in 2018. Some operators who had signed term contracts opted to release the drilling rig and pay an early termination fee for the remaining term of the contract.

During 2016, we recorded $3.1 million in early termination fees, compared to $29.0 million in 2015.

For the year, our drilling revenues decreased 54% from 2015 to $122.1 million. Our average dayrates for the year were $17,784, a 9% decrease from 2015, while our average number of drilling rigs working was 17.4 compared to 34.7 for 2015.

At year-end, our drilling rig fleet consisted of 94 drilling rigs, unchanged from the 94 drilling rigs at the beginning of the year. During December 2016, we sold an idle 1,500 horsepower SCR drilling rig to an unaffiliated third party. With the addition of the ninth BOSS drilling rig we built and placed into service for a third party operator, our total drilling rig fleet remained at 94.

Our rig fleet is located in varying geographic areas with 22 drilling rigs in our Rocky Mountain operations, 54 in our Anadarko Basin operations, 13 in the Permian Basin and five in our Gulf Coast operations. The maximum depth capacities of our various drilling rigs range from 9,500 to 40,000 feet.

Over the years we have worked to strengthen our safety program and 2016 reflected that effort as we achieved our best safety performance in the company’s history. Our safety program not only results in keeping our employees safe but also leads to substantial savings in our daily costs.

OUR CONTRACT DRILLING SEGMENT HAS REBOUNDED WELL FROM A LOW OF 13 OPERATING DRILLING RIGS IN THE SECOND QUARTER REACHING 21 OPERATING RIGS AT YEAR END, AND PRESENTLY WE HAVE 26 OPERATING RIGS, A 100% INCREASE FROM THE TROUGH.

3

MIDSTREAM SEGMENT F

or the year, gathering volumes for our midstream segment increased 18% to 419,217 Mcf per day. Gas processing volumes decreased 15% to 155,461 Mcf per day from 2015, while liquids sold volumes decreased 7% to 536,494 gallons per day from 2015. Revenues for 2016 for our midstream operations decreased 8% from 2015 to $185.9 million.

Our customer base consists of mainly independent producers in Oklahoma, Texas, Kansas, and Pennsylvania. We operate three gas treatment plants, 13 natural gas processing plants, 25 active gathering systems, and approximately 1,465 miles of pipeline.

GATHERED VOLUMES INCREASED

18% TO 419,217

MCF PER DAY

At our Cashion processing facility located in central Oklahoma, our total processing capacity is approximately 45 MMcf per day. In the fourth quarter of 2016, we completed a construction project that allows us to bring additional gas to the Cashion processing plant. Beginning on January 1, 2017, the producer will deliver 10 MMcf per day for five years on a fee-basis to the Cashion processing facility or pay a shortfall fee which is settled on an annual basis. During 2016, we connected a total of seven new wells to this system.

At our Bellmon processing facility located in the Mississippian play in North Central Oklahoma, we installed additional compression in 2016 to be able to handle new third-party volumes. We were able to consolidate two producer-owned gathering systems into our system. During 2016, we connected 15 new wells to this facility. We currently have two processing skids available that provide total processing capacity of 90 MMcf per day.

At our Segno gathering facility located in Southeast Texas, we completed construction projects during 2016 that improved the facility and increased our gathering and dehydration capacity to approximately 120 MMcf per day. Also during 2016, we connected three new wells to this gathering system and there is active drilling and recompletion activity in the area around our system.

In the Appalachian region, at our Pittsburgh Mills gathering system, we continue to connect new well pads to this system. During 2016, we connected four new well pads with a total of 18 new wells to this gathering system. In the fourth quarter of 2016, we started preliminary construction activities to connect the next well pad.

This well pad will have five wells drilled, and we anticipate connecting it in the second quarter of 2017.

Also in the Appalachian area, we began operating our Snow Shoe gathering system in January of 2016. During 2016, we connected three well pads to this system that have a total of six wells. Our average total gathered volume for this new system in 2016 was approximately 10.2 MMcf per day. Preliminary construction continues on the Snow Shoe compressor station, but we do not intend to complete construction and put this compressor station into service until compression services are required on this system.

4

CONNECTED 24 WELLS IN THE APPALACHIAN

BASIN DURING 2016

OPERATIONAL HIGHLIGHTS Year Ended December 31, ($ in thousands except average price amounts)

2016

2015

2014

2013

2012

Proved Oil And Natural Gas Reserves Discounted at 10% (Before Income Taxes)

$575,176

$690,693

$2,099,789

$1,791,903

$1,475,792

Proved Oil And Natural Gas Reserves Discounted at 10% (After Income Taxes)

$518,210

$589,486

$1,435,744

$1,225,976

$1,079,956

405,579

484,868

646,961

581,784

555,647

15,696

16,735

22,667

21,765

21,998

OIL AND NATURAL GAS OPERATIONS DATA:

Total Estimated Proved Reserves: Natural Gas (MMcf) Oil (MBbl) Natural Gas Liquids (MBbl) Equivalent (MBoe)

34,482

37,687

48,529

41,205

35,166

117,774

135,233

179,023

159,934

149,772

Production: Natural Gas (MMcf)

55,735

65,546

58,854

56,757

48,930

Oil (MBbl)

2,974

3,783

3,844

3,360

3,279

Natural Gas Liquids (MBbl)

5,014

5,274

4,628

3,914

2,796

17,277

19,982

18,281

16,734

14,230

$2.07

$2.63

$3.92

$3.32

$3.37

Oil (Per Bbl)

$40.50

$50.79

$89.43

$95.06

$92.60

Natural Gas Liquids (Per Bbl)

$11.26

$10.12

$30.95

$31.79

$31.58

Equivalent (Boe)

$16.92

$20.92

$39.25

$37.77

$39.14

Wells Drilled

21

58

186

149

171

Wells Completed

21

56

181

143

169

100%

97%

97%

96%

99%

Equivalent (MBoe) Average Price: Natural Gas (Per Mcf)

Well Data:

Success Rate

2016 PRODUCING WELL COUNT:

2015

2014

2013

2012

GROSS

NET

GROSS

NET

GROSS

NET

GROSS

NET

GROSS

NET

Natural Gas

4,944

1,770

6,234

2,169

6,369

2,184

6,705

2,182

6,986

2,213

Oil

1,574

635

1,627

650

1,752

663

2,991

599

2,937

564

Total

6,518

2,405

7,861

2,819

8,121

2,847

9,696

2,781

9,923

2,777

2016

2015

2014

2013

2012

94

94

89

121

127

358

516

894

793

773

5,112

7,237

12,551

10,578

10,551

17.4

34.7

75.4

65.0

73.9

Natural Gas Gathered (Mcf/Day)

419,217

353,771

319,348

309,554

250,290

Natural Gas Processed (Mcf/Day)

155,461

182,684

161,282

140,584

133,987

Liquids Sold (Gallons/Day)

536,494

577,513

733,406

543,602

542,578

CONTRACT DRILLING OPERATIONS DATA:

Number of Drilling Rigs Available for Use at Year End Wells Drilled Total Footage Drilled (Feet In 1,000’s) Average Number of Drilling Rigs Utilized MIDSTREAM OPERATIONS DATA:

5

FORM 10-K

6

CORPORATE INFORMATION BOARD OF DIRECTORS

MANAGEMENT

Chairman of the Board Shawnee, Oklahoma

Chairman of the Board

J. MICHAEL ADCOCK

GARY R. CHRISTOPHER Investments Tulsa, Oklahoma

STEVEN B. HILDEBRAND Investments Tulsa, Oklahoma

CARLA S. MASHINSKI Chief Financial Officer Cameron LNG Houston, Texas

WILLIAM B. MORGAN Investments Chandler, Arizona

LARRY C. PAYNE

President and CEO of LESA and Associates, LLC Tulsa, Oklahoma

G. BAILEY PEYTON IV

President, Peyton Holdings Canadian, Texas

LARRY D. PINKSTON

Chief Executive Officer and President Tulsa, Oklahoma

ROBERT J. SULLIVAN, JR.

Manager of Sullivan and Company LLC Tulsa, Oklahoma

DIRECTOR EMERITUS KING P. KIRCHNER

Co-founder, Unit Corporation Tulsa, Oklahoma

J. MICHAEL ADCOCK LARRY D. PINKSTON Chief Executive Officer and President

MARK E. SCHELL

Senior Vice President, General Counsel, and Secretary

TRANSFER AGENT & REGISTRAR Communications concerning the transfer of shares, lost certificates and changes of address should be directed to: American Stock Transfer & Trust Co. 6201 15th Avenue Brooklyn, NY 11219 800.710.0929 www.astfinancial.com

STOCK LISTING

DAVID T. MERRILL

Our common stock trades on the New York Stock Exchange under the symbol: “UNT.”

COMPENSATION COMMITTEE CARLA S. MASHINSKI

During 2016, our average daily trading volume on the NYSE was 1,082,924 shares. Approximately 51.5 million shares were outstanding at the end of 2016.

WILLIAM B. MORGAN

ANNUAL MEETING OF SHAREHOLDERS

Senior Vice President, Chief Financial Officer, and Treasurer

Chair

STEVEN B. HILDEBRAND GARY R. CHRISTOPHER

NOMINATING & GOVERNANCE COMMITTEE WILLIAM B. MORGAN Chair

LARRY C. PAYNE ROBERT J. SULLIVAN JR.

AUDIT COMMITTEE

STEVEN B. HILDEBRAND Chair

GARY R. CHRISTOPHER WILLIAM B. MORGAN LARRY C. PAYNE CARLA S. MASHINSKI

May 3, 2017, 11:00 a.m. Central Time Unit Corporation Headquarters, 8200 S. Unit Drive, Tulsa, Oklahoma 74132

SHAREHOLDER PROFILE

We had 840 shareholders of record at year-end 2016.

INVESTOR RELATIONS

The Form 10-Q reports are available in May, August, and November. The Form 10-K and Form 10-Q are available for viewing on our website at www.unitcorp.com. Copies of the Forms 10-K, 10-Q, and Annual Report, filed with the Securities and Exchange Commission, are available without charge on written request to: Investor Relations Department 8200 South Unit Drive Tulsa, Oklahoma 74132 918.493.7700

INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM PricewaterhouseCoopers LLP Tulsa, Oklahoma

INDEPENDENT PETROLEUM ENGINEERS Ryder Scott Company, L.P.

NYSE: UNT

www.unitcorp.com

Unit Corporation | 2016 Annual Report

GOODRICH PETROLEUM CORPORATION Annual Report 2016

Annual Report 2016

Goodrich Profile Goodrich Petroleum Corporaation is an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas on properties primarily in Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend, Southwest Mississippi and Southeast Louisiana which includes the Tuscaloosa Marine Shale Trend, and South Texas, which includes the Eagle Ford Shale Trend.

Our business strategy is to provide long-term growth in cash flow and net asset value per share, through the growth and expansion of our oil and gas reserves and production. Given the future demand expectations for natural gas, we are concentrating the vast majority of our development efforts on the Haynesville Shale. At December 31, 2016, we had estimated proved reserves of approximately 303 Bcfe, comprised of 286 Bcf of natural gas and 2.8 MMBbls of oil and condensate.

Areas of Operation HAYNESVILLE / BOSSIER SHALE ANGELINA RIVER TREND (“ART”)

Gross (Net) Acres: 13,000 (8,000) Proved Reserves (YE’16 - SEC): 4.2 Bcfe Objective: Haynesville & Bossier Shale

HAYNESVILLE - CORE

Gross (Net) Acres: 35,000 (16,000) Proved Reserves (YE’16): 281.6 Bcfe Objective: Haynesville Shale

MISSISSIPPI

TEXAS LOUISIANA

TUSCALOOSA MARINE SHALE: EAGLE FORD SHALE:

Gross (Net) Acres: 32,400 (14,100) Objectives: Eagle Ford Shale, Pearsall Shale & Buda Lime

Gross (Net) Acres: 215,100 (155,700) Proved Reserves (YE’16): 16.8 Bcfe Objective: Tuscaloosa Marine Shale

Our core acreage position in the Haynesville Shale is expected to drive our Company forward.�

1

Dear Shareholders: 2016 marked a new beginning for Goodrich Petroleum. Amidst a challenging and difficult backdrop for oil prices the last two years, we emerged from restructuring and reorganized in October of 2016 with identical core assets and an improved capital structure that will guide the way to future returns-driven growth. Our future remains bright, and our ability to grow volumes and reserves as the energy industry recovers will help us stand out amongst our peers.

Our core acreage position in the Haynesville Shale is expected to drive our Company forward and will highlight one of the best plays in the country, irrespective of the commodity. Thanks in large part to substantial evolution in completion technologies, we are able to take full advantage of these improvements which are leading to sustainable increases in well productivity. Our ability to generate solid returns as our volumes rebound will set us apart from the industry and form a company with an enormous amount of running room and growth ahead.

Demand for natural gas is expected to grow through the end of this decade, and we have the experience and the assets in the Haynesville to meet those demands.

Our proximity to Henry Hub also means we see favorable pricing for our production compared to many other natural gas plays in the United States. With a net resource potential of over 1 Tcf, and eight years of operational experience in the Haynesville, we have both the asset base and the experience to capitalize on new technologies, efficiencies in the field and improved commodity prices.

We remain focused on growing long-term, per-share cash flow and net asset value.

As one of the first companies to enter the Haynesville in 2008, we had a low entry cost into the basin, and were able to assemble a sizeable footprint in the region.

Combined with improvements in completion technologies and our newly restructured balance sheet, our acreage leaves us in a position to substantially grow volumes, reserves and cash flow over the coming years.

Haynesville Completion Evolution Evolving Completions maximize near-wellbore stimulation

2

ORIGINAL DESIGN

RECENT DESIGN

TESTING

(2008 – 2014)

(2015 – Current)

(Currently)

• 4,600‘ Laterals

• 4,600 – 10,000’ Laterals

• 10,000’ Laterals

• 1,000 lbs/ft Proppant

• 3,000 lbs/ft Proppant

• 5,000+ lbs/ft Proppant

• Hybrid Fluid

• Slick Water Fluid

• Slick Water Fluid

• 300 – 450’ Frac Intervals

• 150 – 250’ Frac Intervals

• 75 – 150’ Frac Intervals

• Cluster Spacing 50 – 70’

• Cluster Spacing 30 – 50’

• Cluster Spacing 10 – 20’

Haynesville Transformation and Renaissance The Haynesville Shale is a proven natural gas resource play experiencing a renaissance as a result of longer laterals and improvements in completion design. We have shared and received technical data with numerous industry participants active in the basin which further enhances our technical knowledge, in-house database and industry best practices.

Our average EUR for the 85 older wells drilled in the Haynesville is approximately 5.4 Bcf, or 1.2 Bcf per 1,000 feet of lateral with short laterals and low proppant concentrations. With the implementations of longer laterals and higher proppant concentrations, we expect to see up to 2.5 Bcf or greater per 1,000 lateral feet, potentially more than doubling our previous ultimate recoveries. Although it is early, recent long-lateral industry wells have produced 3 to 4 Bcf in 120 days and may produce approximately 9 Bcf within the first year if the curves hold, meaning there is potentially even greater upside for future wells.

Our first two wells that we have participated in with the new completion technology have been exceptional, producing well above our high case curve at an initial rate of 72,000 Mcf per day and cumulative production of over 4 Bcf in a little over two months. Needless to say, we are very excited about this confirmation of our exceptional acreage and completion design.

Beyond the impressive well results we are seeing in the play, we also enjoy a number of other economic advantages in the Haynesville as compared to other prolific natural gas basins. Our favorable netbacks to Henry Hub of $0.34 per Mcf for operated wells to approximately $0.87 per Mcf on non-operated wells, including basis and transportation, allow for high realized prices compared to many other natural gas basins. The wells’ high rates of dry gas production also translate into low perunit operating expenses of approximately $0.05 per Mcf initially, which will allow us to drive our Company-wide per unit operating costs substantially lower. Another significant benefit of horizontal Haynesville development is we pay no severance tax until the earlier of payout or two years, further enhancing the economics of our wells. Existing facilities and infrastructure provide for low incremental facility costs, multi-well pads and rapid “spud-to-sales” cycle times to bring the wells to production.

The pay interval is between 150 feet and 200 feet throughout the play.”

Substantial changes in completion techniques have yielded a step-change in well productivity in the Haynesville, and we are positioned to benefit from all the potential upside. With 235 gross potential locations in our North Louisiana core alone, we have the acreage, technology and experience to capitalize on a prolific and wellpositioned natural gas resource.

Haynesville Geological Characteristics The dark organic-rich mudstone-shale that makes up the Haynesville is an exceptional asset from a geological standpoint. With clay content below 30%, the overpressured rock shows a consistent porosity by log of about 15% throughout the pay interval. The Haynesville Shale is deposited in a deep-basin setting with generally south, basin-ward dip at depths ranging from 10,500 feet to 14,000 feet.

With a net pay interval between 150 feet and 200 feet throughout the play, we believe there may be potential upside for future staggered lateral placement in the upper and lower targets, allowing for a higher recovery of gas from tighter spacing.

3

Option value in the Eagle Ford and TMS As oil prices recover, we expect the substantial value of both our Eagle Ford and the Tuscaloosa Marine Shale (TMS) positions to be more highly recognized. We will continue to evaluate what is in the best interest of shareholders regarding each position respectively and will look to capitalize on the best opportunity as it presents itself, but believe our positions in these basins offer tremendous option value.

As an early mover into both plays, we were able to build positions in both regions at a low cost. We paid approximately $1,650 per acre for our Eagle Ford position, and currently hold approximately 100 locations over our 14,000 net acre position. In the TMS, we were able to build an industry-leading position for less than $250 per acre, and continue to see tremendous potential in the basin once oil prices recover to a sufficient level that will allow for competitive rates of return. We believe that the TMS will be a very good candidate for longer laterals and the higher-proppant concentration fracs we are employing currently in the Haynesville. The largest frac we previously pumped in the TMS was about half the size of what we are currently pumping in the Haynesville, and we see a very high correlation between proppant per foot and results.

Looking Ahead As tough as the last couple years have been, we believe the future is bright for our industry and for our shareholders. Our restructured Company and the rejuvenation of the Haynesville Shale both give us a tremendous amount of confidence that we will emerge as an industry leader as the next cycle unfolds.

In closing, we want to thank our entire team for their hard work and dedication to making us a better and more focused Company. We would also like to thank all of you, our fellow shareholders, for your continued support of our business strategy and look forward to sharing with you our numerous successes in the years ahead.

We, and the entire board of directors, are committed to the responsible allocation of capital to develop our asset base with an eye toward building a firm foundation for long-term growth in net asset value per share.

Sincerely,

WALTER G. “GIL� GOODRICH Chairman of the Board and CEO

4

ROBERT C. TURNHAM, JR. President, Chief Operating Office and Director

Board of Directors

Senior Management

Independent Auditors

Walter G. Goodrich (1*) (4*) Chairman of the Board and Chief Executive Officer Goodrich Petroleum Corporation

Walter G. “Gil” Goodrich Chairman of the Board and Chief Executive Officer

Hein & Associates LLP 500 Dallas Street, Suite 2500 Houston, TX 77002

Robert C. Turnham, Jr. (1) (4) President and Chief Operating Officer Goodrich Petroleum Corporation Ronald F. Coleman (3) (5) Retired Energy Executive K. Adam Leight (2*) (3) (4) Managing member of Ansonia Advisors LLC Timothy D. Leuliette (1) (3*) (4) Former President, Chief Executive Officer of Visteon Corporation Steven J. Pully (2) Consultant, Investment Banker Thomas M. Souers Petroleum Engineering Consultant Netherland, Sewell & Associates, Inc. (2) (5)

Robert C. Turnham, Jr. President and Chief Operating Officer Mark E. Ferchau Executive Vice President Michael J. Killelea Executive Vice President, General Counsel and Corporate Secretary Robert T. Barker Vice President, Controller and Chief Financial Officer Clarke A. Denney Senior Vice President, Drilling Timothy D. Lane Senior Vice President, Land and Planning Administration Thomas S. Nemec Senior Vice President, Operations Darrell Knight Vice President, Production Rusty Mondelli Vice President, Information Technology Leslee M. Ranly Vice President, Human Resources and Administration

Transfer Agent American Stock Transfer & Trust Company 6201 15th Street Brooklyn, New York 11219

Corporate Office Corporate Headquarters 801 Louisiana, Suite 700 Houston, Texas 77002

Phone: 713-780-9494

Securities Common Stock traded on OTCQX, symbol GDPP

Annual Meeting of Shareholders The Annual Meeting of Shareholders will be held in Houston, Texas on May 23, 2017 at 11:00 A.M. Central time. A Notice and Proxy Statement will be distributed to all shareholders in April 2017.

SEC Form 10-K The Company’s 2016 annual report to the Securities and Exchange Commission on Form 10-K is available without charge upon request to the Company’s Houston office. This report is prepared for the information of security holders, employees and other interested persons. It is not transmitted in connection with the sale of any security or offer to sell or buy any security.

Web Site Information about Goodrich Petroleum, including an archive of news releases, access to SEC filings, and documents relating to corporate governance, is available from the Company’s website at www.goodrichpetroleum.com.

(1)

Member of Executive Committee

(4)

(2)

Member of Audit Committee

(5)

Member of Hedging Committee Member of Nominating & Corporate Governance Committee

(3)

Member of Compensation Committee

(*)

Denotes Chairman of Committee

Corporate Headquarters 801 Louisiana, Suite 700 | Houston, Texas 77002

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AWARD WINNING DESIGNS Harvest Natural Resources, Gold (2010) Harvest Natural Resources, Gold (2011) Unit Corporation, Silver (2011) PetroQuest Energy, Bronze (2012) Contango Oil & Gas, Silver (2014) Sanchez Energy, Bronze (2014) Whiting Petroleum (2016)